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 Of Principal Executive Offices and Telephone Numbers | Identification No. |
Registrant | Title of each class | Trading Symbol(s) | Name of exchange on which registered |
PNM Resources, Inc. |
PNM Resources, Inc. (“PNMR”) | ☑ | No | ☐ | ||
Public Service Company of New Mexico (“PNM”) | ☑ | No | ☐ | ||
Texas-New Mexico Power Company (“TNMP”) | Yes | ☐ | ☑ |
PNMR | ☑ | No | ☐ | ||
PNM | ☑ | No | ☐ | ||
TNMP | ☑ | No | ☐ |
Accelerated filer | Non-accelerated filer | Smaller reporting company | Emerging growth company | ||||||||||||||||
PNMR | ☑ | ☐ | ☐ | ||||||||||||||||
Large accelerated filer | Accelerated filer | Smaller reporting company | Emerging growth company | ||||||||||||||||
PNM | ☐ | ☐ | ☑ | ||||||||||||||||
Large accelerated filer | Accelerated filer | Smaller reporting company | Emerging growth company | ||||||||||||||||
TNMP | ☐ | ☐ | ☑ |
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 | |
AMS | Advanced Meter System | |
AOCI | Accumulated Other Comprehensive Income | |
APS | Arizona Public Service Company, the operator and a co-owner of PVNGS and Four Corners | |
ASU | Accounting Standards Update | |
BART | Best Available Retrofit Technology | |
BDT | Balanced Draft Technology | |
Board | Board of Directors of PNMR | |
BSER | Best System of Emission Reduction Technology | |
BTMU | MUFG Bank Ltd., formerly the Bank of Tokyo-Mitsubishi UFJ, Ltd. | |
BTMU Term Loan | NM Capital’s $125.0 Million Unsecured Term Loan | |
CAA | Clean Air Act | |
Casa Mesa Wind | Casa Mesa Wind Energy Center | |
CCN | Certificate of Convenience and Necessity | |
CCR | Coal Combustion Residuals | |
CIAC | Contributions in Aid of Construction | |
CO2 | Carbon Dioxide | |
CSA | Coal Supply Agreement | |
DC Circuit | United States Court of Appeals for the District of Columbia Circuit | |
December 2018 Compliance Filing | PNM’s December 31, 2018 filing with the NMPRC regarding SJGS | |
DOE | United States Department of Energy | |
DOI | United States Department of Interior | |
EGU | Electric Generating Unit | |
EIM | California Independent System Operator Western Energy Imbalance Market | |
EIS | Environmental Impact Study | |
EPA | United States Environmental Protection Agency | |
ESA | Endangered Species Act | |
ETA | The New Mexico Energy Transition Act | |
Exchange Act | Securities Exchange Act of 1934 | |
Farmington | The City of Farmington, New Mexico | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
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 | |
kV | Kilovolt | |
KW | Kilowatt | |
KWh | Kilowatt Hour | |
La Luz | La Luz Generating Station | |
LIBOR | London Interbank Offered Rate | |
Lightning Dock Geothermal | Lightning Dock geothermal power facility, also known as the Dale Burgett Geothermal Plant |
Lordsburg | Lordsburg Generating Station | |
Los Alamos | The Incorporated County of Los Alamos, New Mexico | |
Luna | Luna Energy Facility | |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
MMBTU | Million BTUs | |
Moody’s | Moody’s Investor Services, Inc. | |
MW | Megawatts | |
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 | |
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 | |
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 | |
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 Term Loan | PNM’s $200.0 Million Unsecured Term Loan | |
PNM 2019 Term Loan | PNM’s $250.0 Million Unsecured Term Loan | |
PNM Revolving Credit Facility | PNM’s $400.0 Million Unsecured Revolving Credit Facility | |
PNMR | PNM Resources, Inc. and Subsidiaries | |
PNMR 2018 One-Year Term Loan | PNMR’s $150.0 Million One-Year Unsecured Term Loan | |
PNMR 2018 Two-Year Term Loan | PNMR’s $50.0 Million Two-Year Unsecured Term Loan | |
PNMR Development | PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR | |
PNMR Development Revolving Credit Facility | PNMR Development’s $40.0 Million Unsecured Revolving Credit Facility | |
PNMR Development Term Loan | PNMR Development’s $90.0 Million Unsecured Term Loan |
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, as amended by the ETA | |
REC | Renewable Energy Certificates | |
Red Mesa Wind | Red Mesa Wind Energy Center | |
REP | Retail Electricity Provider | |
Rio Bravo | Rio Bravo Generating Station, formerly known as Delta | |
ROE | Return on Equity | |
RPS | Renewable Energy Portfolio Standard | |
S&P | Standard and Poor’s Ratings Services | |
SEC | United States Securities and Exchange Commission | |
SIP | State Implementation Plan | |
SJCC | San Juan Coal Company | |
SJGS | San Juan Generating Station | |
SJGS Abandonment Application | PNM’s July 1, 2019 consolidated application seeking NMPRC approval to retire PNM’s share of SJGS in 2022, for related replacement generating resources, and for the issuance of securitized bonds under the ETA | |
SJGS CSA | San Juan Generating Station Coal Supply Agreement | |
SJGS RA | San Juan Project Restructuring Agreement | |
SNCR | Selective Non-Catalytic Reduction | |
SO2 | Sulfur Dioxide | |
Tax Act | Federal tax reform legislation enacted on December 22, 2017, commonly referred to as the Tax Cuts and Jobs Act | |
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 2018 Rate Case | TNMP’s General Rate Case Application Filed May 30, 2018 | |
TNMP 2018 Term Loan | TNMP’s $35.0 Million Unsecured Term Loan | |
TNMP 2019 Bonds | TNMP’s First Mortgage Bonds issued under the TNMP 2019 Bond Purchase Agreement | |
TNMP 2019 Bond Purchase Agreement | An agreement under which TNMP issued an aggregate of $305.0 Million of First Mortgage Bonds in 2019 | |
TNMP Revolving Credit Facility | TNMP’s $75.0 Million Secured Revolving Credit Facility | |
Tri-State | Tri-State Generation and Transmission Association, Inc. | |
Tucson | Tucson Electric Power Company | |
UAMPS | Utah Associated Municipal Power Systems | |
US Supreme Court | United States Supreme Court | |
Valencia | Valencia Energy Facility | |
VIE | Variable Interest Entity | |
WEG | WildEarth Guardians | |
Western Spirit Line | A 165-mile 345 kV transmission line that PNM has agreed to purchase, subject to regulatory approval | |
Westmoreland | Westmoreland Coal Company | |
Westmoreland Loan | $125.0 Million of funding provided by NM Capital to WSJ | |
WSJ | Westmoreland San Juan, LLC, formerly an indirect wholly-owned subsidiary of Westmoreland, and former owner of SJCC | |
WSJ LLC | Westmoreland San Juan Mining, LLC, a subsidiary of Westmoreland Mining Holdings, LLC, and current owner of SJCC |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands, except per share amounts) | |||||||||||||||
Electric Operating Revenues: | |||||||||||||||
Contracts with customers | $ | $ | $ | $ | |||||||||||
Alternative revenue programs | |||||||||||||||
Other electric operating revenue | |||||||||||||||
Total electric operating revenues | |||||||||||||||
Operating Expenses: | |||||||||||||||
Cost of energy | |||||||||||||||
Administrative and general | |||||||||||||||
Energy production costs | |||||||||||||||
Regulatory disallowances and restructuring costs | |||||||||||||||
Depreciation and amortization | |||||||||||||||
Transmission and distribution costs | |||||||||||||||
Taxes other than income taxes | |||||||||||||||
Total operating expenses | |||||||||||||||
Operating income (loss) | ( | ) | ( | ) | |||||||||||
Other Income and Deductions: | |||||||||||||||
Interest income | |||||||||||||||
Gains (losses) on investment securities | ( | ) | ( | ) | |||||||||||
Other income | |||||||||||||||
Other (deductions) | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Net other income and deductions | |||||||||||||||
Interest Charges | |||||||||||||||
Earnings (Loss) before Income Taxes | ( | ) | ( | ) | |||||||||||
Income Taxes (Benefits) | ( | ) | ( | ) | |||||||||||
Net Earnings (Loss) | ( | ) | ( | ) | |||||||||||
(Earnings) Attributable to Valencia Non-controlling Interest | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Preferred Stock Dividend Requirements of Subsidiary | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Net Earnings (Loss) Attributable to PNMR | $ | ( | ) | $ | $ | ( | ) | $ | |||||||
Net Earnings (Loss) Attributable to PNMR per Common Share: | |||||||||||||||
Basic | $ | ( | ) | $ | $ | ( | ) | $ | |||||||
Diluted | $ | ( | ) | $ | $ | ( | ) | $ | |||||||
Dividends Declared per Common Share | $ | $ | $ | $ |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Net Earnings (Loss) | $ | ( | ) | $ | $ | ( | ) | $ | |||||||
Other Comprehensive Income: | |||||||||||||||
Unrealized Gains on Available-for-Sale Securities: | |||||||||||||||
Unrealized holding gains arising during the period, net of income tax (expense) of $(2,250), $(91), $(4,048), and $(374) | |||||||||||||||
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,251, $126, $1,423, and $794 | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Pension Liability Adjustment: | |||||||||||||||
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(470), $(482), $(940), and $(962) | |||||||||||||||
Fair Value Adjustment for Cash Flow Hedges: | |||||||||||||||
Change in fair market value, net of income tax (expense) benefit of $494, $(143), $805, and $(615) | ( | ) | ( | ) | |||||||||||
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(65), $(12), $(133), and $1 | ( | ) | |||||||||||||
Total Other Comprehensive Income | |||||||||||||||
Comprehensive Income (Loss) | ( | ) | ( | ) | |||||||||||
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Preferred Stock Dividend Requirements of Subsidiary | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Comprehensive Income (Loss) Attributable to PNMR | $ | ( | ) | $ | $ | ( | ) | $ |
Six Months Ended June 30, | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings (loss) | $ | ( | ) | $ | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | |||||||
Deferred income tax expense | ( | ) | |||||
(Gains) losses on investment securities | ( | ) | |||||
Stock based compensation expense | |||||||
Regulatory disallowances and restructuring costs | |||||||
Allowance for equity funds used during construction | ( | ) | ( | ) | |||
Other, net | |||||||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | ( | ) | |||||
Materials, supplies, and fuel stock | ( | ) | ( | ) | |||
Other current assets | ( | ) | ( | ) | |||
Other assets | |||||||
Accounts payable | ( | ) | ( | ) | |||
Accrued interest and taxes | ( | ) | ( | ) | |||
Other current liabilities | ( | ) | ( | ) | |||
Other liabilities | ( | ) | ( | ) | |||
Net cash flows from operating activities | |||||||
Cash Flows From Investing Activities: | |||||||
Additions to utility plant | ( | ) | ( | ) | |||
Proceeds from sales of investment securities | |||||||
Purchases of investment securities | ( | ) | ( | ) | |||
Principal repayments on Westmoreland Loan | |||||||
Investments in NMRD | ( | ) | ( | ) | |||
Other, net | ( | ) | ( | ) | |||
Net cash flows from investing activities | ( | ) | ( | ) |
Six Months Ended June 30, | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Cash Flows From Financing Activities: | |||||||
Revolving credit facilities borrowings (repayments), net | ( | ) | |||||
Long-term borrowings | |||||||
Repayment of long-term debt | ( | ) | ( | ) | |||
Proceeds from stock option exercise | |||||||
Awards of common stock | ( | ) | ( | ) | |||
Dividends paid | ( | ) | ( | ) | |||
Valencia’s transactions with its owner | ( | ) | ( | ) | |||
Refunds paid under transmission interconnection arrangements | ( | ) | ( | ) | |||
Debt issuance costs and other, net | ( | ) | ( | ) | |||
Net cash flows from financing activities | |||||||
Change in Cash, Restricted Cash, and Equivalents | |||||||
Cash, Restricted Cash, and Equivalents at Beginning of Period | |||||||
Cash, Restricted Cash, and Equivalents at End of Period | $ | $ | |||||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | $ | |||||
Income taxes paid (refunded), net | $ | ( | ) | $ | |||
Supplemental schedule of noncash investing activities: | |||||||
(Increase) decrease in accrued plant additions | $ | $ |
June 30, 2019 | December 31, 2018 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | $ | |||||
Accounts receivable, net of allowance for uncollectible accounts of $1,178 and $1,406 | |||||||
Unbilled revenues | |||||||
Other receivables | |||||||
Materials, supplies, and fuel stock | |||||||
Regulatory assets | |||||||
Income taxes receivable | |||||||
Other current assets | |||||||
Total current assets | |||||||
Other Property and Investments: | |||||||
Investment securities | |||||||
Equity investment in NMRD | |||||||
Other investments | |||||||
Non-utility property, net | |||||||
Total other property and investments | |||||||
Utility Plant: | |||||||
Plant in service, held for future use, and to be abandoned | |||||||
Less accumulated depreciation and amortization | |||||||
Construction work in progress | |||||||
Nuclear fuel, net of accumulated amortization of $42,410 and $42,511 | |||||||
Net utility plant | |||||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | |||||||
Goodwill | |||||||
Operating lease right-of-use assets, net of accumulated amortization | — | ||||||
Other deferred charges | |||||||
Total deferred charges and other assets | |||||||
$ | $ |
June 30, 2019 | December 31, 2018 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | $ | |||||
Current installments of long-term debt | |||||||
Accounts payable | |||||||
Customer deposits | |||||||
Accrued interest and taxes | |||||||
Regulatory liabilities | |||||||
Operating lease liabilities | — | ||||||
Dividends declared | |||||||
Other current liabilities | |||||||
Total current liabilities | |||||||
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | |||||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | |||||||
Regulatory liabilities | |||||||
Asset retirement obligations | |||||||
Accrued pension liability and postretirement benefit cost | |||||||
Operating lease liabilities | — | ||||||
Other deferred credits | |||||||
Total deferred credits and other liabilities | |||||||
Total liabilities | |||||||
Commitments and Contingencies (Note 11) | |||||||
Cumulative Preferred Stock of Subsidiary | |||||||
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | |||||||
Equity: | |||||||
PNMR common stockholders' equity: | |||||||
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares) | |||||||
Accumulated other comprehensive income (loss), net of income taxes | ( | ) | ( | ) | |||
Retained earnings | |||||||
Total PNMR common stockholders’ equity | |||||||
Non-controlling interest in Valencia | |||||||
Total equity | |||||||
$ | $ | ||||||
Attributable to PNMR | Non- controlling Interest in Valencia | ||||||||||||||||||||||
Common Stock | AOCI | Retained Earnings | Total PNMR Common Stockholders’ Equity | Total Equity | |||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Balance at March 31, 2019 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Net earnings (loss) before subsidiary preferred stock dividends | — | — | ( | ) | ( | ) | ( | ) | |||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Subsidiary preferred stock dividends | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Proceeds from stock option exercise | — | — | — | ||||||||||||||||||||
Awards of common stock | ( | ) | — | — | ( | ) | — | ( | ) | ||||||||||||||
Stock based compensation expense | — | — | — | ||||||||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2019 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Balance at December 31, 2018 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Net earnings (loss) before subsidiary preferred stock dividends | — | — | ( | ) | ( | ) | ( | ) | |||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Subsidiary preferred stock dividends | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Dividends declared on common stock | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Proceeds from stock option exercise | — | — | — | ||||||||||||||||||||
Awards of common stock | ( | ) | — | — | ( | ) | — | ( | ) | ||||||||||||||
Stock based compensation expense | — | — | — | ||||||||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2019 | $ | $ | ( | ) | $ | $ | $ | $ |
Balance at March 31, 2018 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Net earnings before subsidiary preferred stock dividends | — | — | |||||||||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Subsidiary preferred stock dividends | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Proceeds from stock option exercise | — | — | — | ||||||||||||||||||||
Awards of common stock | ( | ) | — | — | ( | ) | — | ( | ) | ||||||||||||||
Stock based compensation expense | — | — | — | ||||||||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2018 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Balance at December 31, 2017, as originally reported | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Cumulative effect adjustment (Note 7) | — | ( | ) | — | — | — | |||||||||||||||||
Balance at January 1, 2018, as adjusted | ( | ) | |||||||||||||||||||||
Net earnings before subsidiary preferred stock dividends | — | — | |||||||||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Subsidiary preferred stock dividends | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Dividends declared on common stock | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Proceeds from stock option exercise | — | — | — | ||||||||||||||||||||
Awards of common stock | ( | ) | — | — | ( | ) | — | ( | ) | ||||||||||||||
Stock based compensation expense | — | — | — | ||||||||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2018 | $ | $ | ( | ) | $ | $ | $ | $ |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Electric Operating Revenues: | |||||||||||||||
Contracts with customers | $ | $ | $ | $ | |||||||||||
Alternative revenue programs | |||||||||||||||
Other electric operating revenue | |||||||||||||||
Total electric operating revenues | |||||||||||||||
Operating Expenses: | |||||||||||||||
Cost of energy | |||||||||||||||
Administrative and general | |||||||||||||||
Energy production costs | |||||||||||||||
Regulatory disallowances and restructuring costs | |||||||||||||||
Depreciation and amortization | |||||||||||||||
Transmission and distribution costs | |||||||||||||||
Taxes other than income taxes | |||||||||||||||
Total operating expenses | |||||||||||||||
Operating income (loss) | ( | ) | ( | ) | |||||||||||
Other Income and Deductions: | |||||||||||||||
Interest income | |||||||||||||||
Gains (losses) on investment securities | ( | ) | ( | ) | |||||||||||
Other income | |||||||||||||||
Other (deductions) | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Net other income and deductions | |||||||||||||||
Interest Charges | |||||||||||||||
Earnings (Loss) before Income Taxes | ( | ) | ( | ) | |||||||||||
Income Taxes (Benefits) | ( | ) | ( | ) | |||||||||||
Net Earnings (Loss) | ( | ) | ( | ) | |||||||||||
(Earnings) Attributable to Valencia Non-controlling Interest | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Net Earnings (Loss) Attributable to PNM | ( | ) | ( | ) | |||||||||||
Preferred Stock Dividends Requirements | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Net Earnings (Loss) Available for PNM Common Stock | $ | ( | ) | $ | $ | ( | ) | $ |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Net Earnings (Loss) | $ | ( | ) | $ | $ | ( | ) | $ | |||||||
Other Comprehensive Income: | |||||||||||||||
Unrealized Gains on Available-for-Sale Securities: | |||||||||||||||
Unrealized holding gains arising during the period, net of income tax (expense) of $(2,250), $(91), $(4,048), and $(374) | |||||||||||||||
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $1,251, $126, $1,423, and $794 | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Pension Liability Adjustment: | |||||||||||||||
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(470), $(482), $(940), and $(962) | |||||||||||||||
Total Other Comprehensive Income | |||||||||||||||
Comprehensive Income (Loss) | ( | ) | ( | ) | |||||||||||
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Comprehensive Income (Loss) Attributable to PNM | $ | ( | ) | $ | $ | ( | ) | $ |
Six Months Ended June 30, | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings (loss) | $ | ( | ) | $ | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | |||||||
Deferred income tax expense | ( | ) | |||||
(Gains) losses on investment securities | ( | ) | |||||
Regulatory disallowances and restructuring costs | |||||||
Allowance for equity funds used during construction | ( | ) | ( | ) | |||
Other, net | |||||||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | ( | ) | |||||
Materials, supplies, and fuel stock | ( | ) | ( | ) | |||
Other current assets | ( | ) | ( | ) | |||
Other assets | |||||||
Accounts payable | ( | ) | ( | ) | |||
Accrued interest and taxes | ( | ) | |||||
Other current liabilities | ( | ) | |||||
Other liabilities | ( | ) | ( | ) | |||
Net cash flows from operating activities | |||||||
Cash Flows From Investing Activities: | |||||||
Additions to utility plant | ( | ) | ( | ) | |||
Proceeds from sales of investment securities | |||||||
Purchases of investment securities | ( | ) | ( | ) | |||
Other, net | |||||||
Net cash flows from investing activities | ( | ) | ( | ) |
Six Months Ended June 30, | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Cash Flows From Financing Activities: | |||||||
Revolving credit facilities borrowings (repayments), net | ( | ) | ( | ) | |||
Short-term borrowings (repayments) – affiliate, net | ( | ) | |||||
Long-term borrowings | |||||||
Repayment of long-term debt | ( | ) | ( | ) | |||
Dividends paid | ( | ) | ( | ) | |||
Valencia’s transactions with its owner | ( | ) | ( | ) | |||
Amounts received under transmission interconnection arrangements | |||||||
Refunds paid under transmission interconnection arrangements | ( | ) | ( | ) | |||
Debt issuance costs and other, net | ( | ) | ( | ) | |||
Net cash flows from financing activities | |||||||
Change in Cash, Restricted Cash, and Equivalents | |||||||
Cash, Restricted Cash, and Equivalents at Beginning of Period | |||||||
Cash, Restricted Cash, and Equivalents at End of Period | $ | $ | |||||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | $ | |||||
Income taxes paid (refunded), net | $ | ( | ) | $ | |||
Supplemental schedule of noncash investing activities: | |||||||
(Increase) decrease in accrued plant additions | $ | $ | ( | ) |
June 30, 2019 | December 31, 2018 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | $ | |||||
Accounts receivable, net of allowance for uncollectible accounts of $1,178 and $1,406 | |||||||
Unbilled revenues | |||||||
Other receivables | |||||||
Affiliate receivables | |||||||
Materials, supplies, and fuel stock | |||||||
Regulatory assets | |||||||
Income taxes receivable | |||||||
Other current assets | |||||||
Total current assets | |||||||
Other Property and Investments: | |||||||
Investment securities | |||||||
Other investments | |||||||
Non-utility property, net | |||||||
Total other property and investments | |||||||
Utility Plant: | |||||||
Plant in service, held for future use, and to be abandoned | |||||||
Less accumulated depreciation and amortization | |||||||
Construction work in progress | |||||||
Nuclear fuel, net of accumulated amortization of $42,410 and $42,511 | |||||||
Net utility plant | |||||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | |||||||
Goodwill | |||||||
Operating lease right-of-use assets, net of accumulated amortization | — | ||||||
Other deferred charges | |||||||
Total deferred charges and other assets | |||||||
$ | $ | ||||||
June 30, 2019 | December 31, 2018 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | $ | |||||
Short-term debt - affiliate | |||||||
Current installments of long-term debt | |||||||
Accounts payable | |||||||
Affiliate payables | |||||||
Customer deposits | |||||||
Accrued interest and taxes | |||||||
Regulatory liabilities | |||||||
Operating lease liabilities | — | ||||||
Dividends declared | |||||||
Other current liabilities | |||||||
Total current liabilities | |||||||
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | |||||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | |||||||
Regulatory liabilities | |||||||
Asset retirement obligations | |||||||
Accrued pension liability and postretirement benefit cost | |||||||
Operating lease liabilities | — | ||||||
Other deferred credits | |||||||
Total deferred credits and liabilities | |||||||
Total liabilities | |||||||
Commitments and Contingencies (Note 11) | |||||||
Cumulative Preferred Stock | |||||||
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | |||||||
Equity: | |||||||
PNM common stockholder’s equity: | |||||||
Common stock (no par value; 40,000,000 shares authorized; issued and outstanding 39,117,799 shares) | |||||||
Accumulated other comprehensive income (loss), net of income taxes | ( | ) | ( | ) | |||
Retained earnings | |||||||
Total PNM common stockholder’s equity | |||||||
Non-controlling interest in Valencia | |||||||
Total equity | |||||||
$ | $ |
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 March 31, 2019 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Net earnings (loss) | — | — | ( | ) | ( | ) | ( | ) | |||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Dividends declared on preferred stock | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2019 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Balance at December 31, 2018 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Net earnings (loss) | — | — | ( | ) | ( | ) | ( | ) | |||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Dividends declared on preferred stock | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2019 | $ | $ | ( | ) | $ | $ | $ | $ |
Balance at March 31, 2018 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Net earnings | — | — | |||||||||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Dividends declared on preferred stock | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2018 | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Balance at December 31, 2017, as originally reported | $ | $ | ( | ) | $ | $ | $ | $ | |||||||||||||||
Cumulative effect adjustment (Note 7) | — | ( | ) | — | — | — | |||||||||||||||||
Balance at January 1, 2018, as adjusted | ( | ) | |||||||||||||||||||||
Net earnings | — | — | |||||||||||||||||||||
Total other comprehensive income | — | — | — | ||||||||||||||||||||
Dividends declared on preferred stock | — | — | ( | ) | ( | ) | — | ( | ) | ||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | ( | ) | ( | ) | |||||||||||||||
Balance at June 30, 2018 | $ | $ | ( | ) | $ | $ | $ | $ |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Electric Operating Revenues: | |||||||||||||||
Contracts with customers | $ | $ | $ | $ | |||||||||||
Alternative revenue programs | |||||||||||||||
Total Electric Operating Revenues | |||||||||||||||
Operating Expenses: | |||||||||||||||
Cost of energy | |||||||||||||||
Administrative and general | |||||||||||||||
Depreciation and amortization | |||||||||||||||
Transmission and distribution costs | |||||||||||||||
Taxes other than income taxes | |||||||||||||||
Total operating expenses | |||||||||||||||
Operating income | |||||||||||||||
Other Income and Deductions: | |||||||||||||||
Other income | |||||||||||||||
Other (deductions) | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Net other income and deductions | |||||||||||||||
Interest Charges | |||||||||||||||
Earnings before Income Taxes | |||||||||||||||
Income Taxes | |||||||||||||||
Net Earnings | $ | $ | $ | $ |
Six Months Ended June 30, | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings | $ | $ | |||||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | |||||||
Deferred income tax expense (benefit) | ( | ) | ( | ) | |||
Allowance for equity funds used during construction and other, net | ( | ) | ( | ) | |||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | ( | ) | ( | ) | |||
Materials and supplies | ( | ) | ( | ) | |||
Other current assets | ( | ) | ( | ) | |||
Other assets | ( | ) | |||||
Accounts payable | ( | ) | |||||
Accrued interest and taxes | |||||||
Other current liabilities | |||||||
Other liabilities | ( | ) | |||||
Net cash flows from operating activities | |||||||
Cash Flows From Investing Activities: | |||||||
Additions to utility plant | ( | ) | ( | ) | |||
Net cash flows from investing activities | ( | ) | ( | ) | |||
Cash Flow From Financing Activities: | |||||||
Revolving credit facilities borrowings (repayments), net | |||||||
Short-term borrowings (repayments) – affiliate, net | |||||||
Long-term borrowings | |||||||
Repayment of long-term debt | ( | ) | |||||
Dividends paid | ( | ) | ( | ) | |||
Debt issuance costs and other, net | ( | ) | ( | ) | |||
Net cash flows from financing activities | |||||||
Change in Cash and Cash Equivalents | ( | ) | |||||
Cash and Cash Equivalents at Beginning of Period | |||||||
Cash and Cash Equivalents at End of Period | $ | $ | |||||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | $ | |||||
Income taxes paid (refunded), net | $ | $ | |||||
Supplemental schedule of noncash investing activities: | |||||||
(Increase) decrease in accrued plant additions | $ | $ |
June 30, 2019 | December 31, 2018 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | $ | |||||
Accounts receivable | |||||||
Unbilled revenues | |||||||
Other receivables | |||||||
Affiliate receivables | |||||||
Materials and supplies | |||||||
Regulatory assets | |||||||
Other current assets | |||||||
Total current assets | |||||||
Other Property and Investments: | |||||||
Other investments | |||||||
Non-utility property, net | |||||||
Total other property and investments | |||||||
Utility Plant: | |||||||
Plant in service and plant held for future use | |||||||
Less accumulated depreciation and amortization | |||||||
Construction work in progress | |||||||
Net utility plant | |||||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | |||||||
Goodwill | |||||||
Operating lease right-of-use assets, net of accumulated amortization | — | ||||||
Other deferred charges | |||||||
Total deferred charges and other assets | |||||||
$ | $ |
June 30, 2019 | December 31, 2018 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | $ | |||||
Short-term debt – affiliate | |||||||
Accounts payable | |||||||
Affiliate payables | |||||||
Accrued interest and taxes | |||||||
Regulatory liabilities | |||||||
Operating lease liabilities | — | ||||||
Other current liabilities | |||||||
Total current liabilities | |||||||
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs | |||||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | |||||||
Regulatory liabilities | |||||||
Asset retirement obligations | |||||||
Accrued pension liability and postretirement benefit cost | |||||||
Operating lease liabilities | — | ||||||
Other deferred credits | |||||||
Total deferred credits and other liabilities | |||||||
Total liabilities | |||||||
Commitments and Contingencies (Note 11) | |||||||
Common Stockholder's Equity: | |||||||
Common stock ($10 par value; 12,000,000 shares authorized; issued and outstanding 6,358 shares) | |||||||
Paid-in-capital | |||||||
Retained earnings | |||||||
Total common stockholder’s equity | |||||||
$ | $ |
Common Stock | Paid-in Capital | Retained Earnings | Total Common Stockholder’s Equity | ||||||||||||
(In thousands) | |||||||||||||||
Balance at March 31, 2019 | $ | $ | $ | $ | |||||||||||
Net earnings | — | — | |||||||||||||
Dividends declared on common stock | — | — | ( | ) | ( | ) | |||||||||
Balance at June 30, 2019 | $ | $ | $ | $ | |||||||||||
Balance at December 31, 2018 | $ | $ | $ | $ | |||||||||||
Net earnings | — | — | |||||||||||||
Dividends declared on common stock | — | — | ( | ) | ( | ) | |||||||||
Balance at June 30, 2019 | $ | $ | $ | $ |
Balance at March 31, 2018 | $ | $ | $ | $ | |||||||||||
Net earnings | — | — | |||||||||||||
Dividends declared on common stock | — | — | ( | ) | ( | ) | |||||||||
Balance at June 30, 2018 | $ | $ | $ | $ | |||||||||||
Balance at December 31, 2017 | $ | $ | $ | $ | |||||||||||
Net earnings | — | — | |||||||||||||
Dividends declared on common stock | — | — | ( | ) | ( | ) | |||||||||
Balance at June 30, 2018 | $ | $ | $ | $ |
(1) | Significant Accounting Policies and Responsibility for Financial Statements |
Results of Operations | |||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Operating revenues | $ | $ | $ | $ | |||||||||||
Operating expenses | |||||||||||||||
Net earnings | $ | $ | $ | $ |
Financial Position | |||||||
June 30, | December 31, | ||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Current assets | $ | $ | |||||
Net property, plant, and equipment | |||||||
Total assets | |||||||
Current liabilities | |||||||
Owners’ equity | $ | $ |
(2) | Segment Information |
PNM | TNMP | Corporate and Other | PNMR Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Three Months Ended June 30, 2019 | |||||||||||||||
Electric operating revenues | $ | $ | $ | $ | |||||||||||
Cost of energy | |||||||||||||||
Utility margin | |||||||||||||||
Other operating expenses | ( | ) | |||||||||||||
Depreciation and amortization | |||||||||||||||
Operating income (loss) | ( | ) | ( | ) | ( | ) | |||||||||
Interest income | ( | ) | |||||||||||||
Other income (deductions) | ( | ) | |||||||||||||
Interest charges | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Segment earnings (loss) before income taxes | ( | ) | ( | ) | ( | ) | |||||||||
Income taxes (benefit) | ( | ) | ( | ) | ( | ) | |||||||||
Segment earnings (loss) | ( | ) | ( | ) | ( | ) | |||||||||
Valencia non-controlling interest | ( | ) | ( | ) | |||||||||||
Subsidiary preferred stock dividends | ( | ) | ( | ) | |||||||||||
Segment earnings (loss) attributable to PNMR | $ | ( | ) | $ | $ | ( | ) | $ | ( | ) | |||||
Six Months Ended June 30, 2019 | |||||||||||||||
Electric operating revenues | $ | $ | $ | $ | |||||||||||
Cost of energy | |||||||||||||||
Utility margin | |||||||||||||||
Other operating expenses | ( | ) | |||||||||||||
Depreciation and amortization | |||||||||||||||
Operating income (loss) | ( | ) | ( | ) | ( | ) | |||||||||
Interest income | ( | ) | |||||||||||||
Other income (deductions) | ( | ) | |||||||||||||
Interest charges | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Segment earnings (loss) before income taxes | ( | ) | ( | ) | ( | ) | |||||||||
Income taxes (benefit) | ( | ) | ( | ) | ( | ) | |||||||||
Segment earnings (loss) | ( | ) | ( | ) | ( | ) | |||||||||
Valencia non-controlling interest | ( | ) | ( | ) | |||||||||||
Subsidiary preferred stock dividends | ( | ) | ( | ) | |||||||||||
Segment earnings (loss) attributable to PNMR | $ | ( | ) | $ | $ | ( | ) | $ | ( | ) | |||||
At June 30, 2019: | |||||||||||||||
Total Assets | $ | $ | $ | $ | |||||||||||
Goodwill | $ | $ | $ | $ |
PNM | TNMP | Corporate and Other | PNMR Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Three Months Ended June 30, 2018 | |||||||||||||||
Electric operating revenues | $ | $ | $ | $ | |||||||||||
Cost of energy | |||||||||||||||
Utility margin | |||||||||||||||
Other operating expenses | ( | ) | |||||||||||||
Depreciation and amortization | |||||||||||||||
Operating income (loss) | ( | ) | |||||||||||||
Interest income | |||||||||||||||
Other income (deductions) | ( | ) | ( | ) | ( | ) | |||||||||
Interest charges | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Segment earnings (loss) before income taxes | ( | ) | |||||||||||||
Income taxes (benefit) | ( | ) | |||||||||||||
Segment earnings (loss) | ( | ) | |||||||||||||
Valencia non-controlling interest | ( | ) | ( | ) | |||||||||||
Subsidiary preferred stock dividends | ( | ) | ( | ) | |||||||||||
Segment earnings (loss) attributable to PNMR | $ | $ | $ | ( | ) | $ | |||||||||
Three Months Ended June 30, 2018 | |||||||||||||||
Electric operating revenues | $ | $ | $ | $ | |||||||||||
Cost of energy | |||||||||||||||
Utility margin | |||||||||||||||
Other operating expenses | ( | ) | |||||||||||||
Depreciation and amortization | |||||||||||||||
Operating income (loss) | ( | ) | |||||||||||||
Interest income | |||||||||||||||
Other income (deductions) | ( | ) | ( | ) | ( | ) | |||||||||
Interest charges | ( | ) | ( | ) | ( | ) | ( | ) | |||||||
Segment earnings (loss) before income taxes | ( | ) | |||||||||||||
Income taxes (benefit) | ( | ) | |||||||||||||
Segment earnings (loss) | ( | ) | |||||||||||||
Valencia non-controlling interest | ( | ) | ( | ) | |||||||||||
Subsidiary preferred stock dividends | ( | ) | ( | ) | |||||||||||
Segment earnings (loss) attributable to PNMR | $ | $ | $ | ( | ) | $ | |||||||||
At June 30, 2018: | |||||||||||||||
Total Assets | $ | $ | $ | $ | |||||||||||
Goodwill | $ | $ | $ | $ |
(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, 2018 | $ | $ | ( | ) | $ | ( | ) | $ | $ | ( | ) | ||||||||
Amounts reclassified from AOCI (pre-tax) | ( | ) | ( | ) | ( | ) | |||||||||||||
Income tax impact of amounts reclassified | ( | ) | ( | ) | |||||||||||||||
Other OCI changes (pre-tax) | — | ( | ) | ||||||||||||||||
Income tax impact of other OCI changes | ( | ) | — | ( | ) | ( | ) | ||||||||||||
Net after-tax change | ( | ) | |||||||||||||||||
Balance at June 30, 2019 | $ | $ | ( | ) | $ | ( | ) | $ | ( | ) | $ | ( | ) |
Balance at December 31, 2017, as originally reported | $ | $ | ( | ) | $ | ( | ) | $ | $ | ( | ) | ||||||||
Cumulative effect adjustment (Note 7) | ( | ) | — | ( | ) | — | ( | ) | |||||||||||
Balance at January 1, 2018, as adjusted | ( | ) | ( | ) | ( | ) | |||||||||||||
Amounts reclassified from AOCI (pre-tax) | ( | ) | ( | ) | |||||||||||||||
Income tax impact of amounts reclassified | ( | ) | ( | ) | ( | ) | |||||||||||||
Other OCI changes (pre-tax) | — | ||||||||||||||||||
Income tax impact of other OCI changes | ( | ) | — | ( | ) | ( | ) | ( | ) | ||||||||||
Net after-tax change | ( | ) | |||||||||||||||||
Balance at June 30, 2018 | $ | $ | ( | ) | $ | ( | ) | $ | $ | ( | ) |
(4) | Earnings Per Share |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands, except per share amounts) | |||||||||||||||
Net Earnings (Loss) Attributable to PNMR | $ | ( | ) | $ | $ | ( | ) | $ | |||||||
Average Number of Common Shares: | |||||||||||||||
Outstanding during period | |||||||||||||||
Vested awards of restricted stock | |||||||||||||||
Average Shares – Basic | |||||||||||||||
Dilutive Effect of Common Stock Equivalents:(1) | |||||||||||||||
Stock options and restricted stock | |||||||||||||||
Average Shares – Diluted | |||||||||||||||
Net Earnings (Loss) Per Share of Common Stock: | |||||||||||||||
Basic | $ | ( | ) | $ | $ | ( | ) | $ | |||||||
Diluted(1) | $ | ( | ) | $ | $ | ( | ) | $ |
(5) | Electric Operating Revenues |
PNM | TNMP | PNMR Consolidated | ||||||||||
Three Months Ended June 30, 2019 | (In thousands) | |||||||||||
Electric Operating Revenues: | ||||||||||||
Contracts with customers: | ||||||||||||
Retail electric revenue | ||||||||||||
Residential | $ | $ | $ | |||||||||
Commercial | ||||||||||||
Industrial | ||||||||||||
Public authority | ||||||||||||
Economy energy service | ||||||||||||
Transmission | ||||||||||||
Miscellaneous | ||||||||||||
Total revenues from contracts with customers | ||||||||||||
Alternative revenue programs | ||||||||||||
Other electric operating revenues | ||||||||||||
Total Electric Operating Revenues | $ | $ | $ | |||||||||
PNM | TNMP | PNMR Consolidated | ||||||||||
Six Months Ended June 30, 2019 | (In thousands) | |||||||||||
Electric Operating Revenues: | ||||||||||||
Contracts with customers: | ||||||||||||
Retail electric revenue | ||||||||||||
Residential | $ | $ | $ | |||||||||
Commercial | ||||||||||||
Industrial | ||||||||||||
Public authority | ||||||||||||
Economy energy service | ||||||||||||
Transmission | ||||||||||||
Miscellaneous | ||||||||||||
Total revenues from contracts with customers | ||||||||||||
Alternative revenue programs | ||||||||||||
Other electric operating revenues | ||||||||||||
Total Electric Operating Revenues | $ | $ | $ |
Three Months Ended June 30, 2018 | ||||||||||||
Electric Operating Revenues: | ||||||||||||
Contracts with customers: | ||||||||||||
Retail electric revenue | ||||||||||||
Residential | $ | $ | $ | |||||||||
Commercial | ||||||||||||
Industrial | ||||||||||||
Public authority | ||||||||||||
Economy energy service | ||||||||||||
Transmission | ||||||||||||
Miscellaneous | ||||||||||||
Total revenues from contracts with customers | ||||||||||||
Alternative revenue programs | ||||||||||||
Other electric operating revenues | ||||||||||||
Total Electric Operating Revenues | $ | $ | $ | |||||||||
Six Months Ended June 30, 2018 | ||||||||||||
Electric Operating Revenues: | ||||||||||||
Contracts with customers: | ||||||||||||
Retail electric revenue | ||||||||||||
Residential | $ | $ | $ | |||||||||
Commercial | ||||||||||||
Industrial | ||||||||||||
Public authority | ||||||||||||
Economy energy service | ||||||||||||
Transmission | ||||||||||||
Miscellaneous | ||||||||||||
Total revenues from contracts with customers | ||||||||||||
Alternative revenue programs | ||||||||||||
Other electric operating revenues | ||||||||||||
Total Electric Operating Revenues | $ | $ | $ |
PNM | TNMP | PNMR Consolidated | ||||||||||
(In thousands) | ||||||||||||
Balance at December 31, 2018 | $ | $ | $ | |||||||||
Consideration received in advance of service to be provided | ||||||||||||
Deferred revenue earned | ( | ) | ( | ) | ( | ) | ||||||
Balance at June 30, 2019 | $ | $ | $ |
(6) | Variable Interest Entities |
Results of Operations | |||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Operating revenues | $ | $ | $ | $ | |||||||||||
Operating expenses | |||||||||||||||
Earnings attributable to non-controlling interest | $ | $ | $ | $ |
Financial Position | |||||||
June 30, | December 31, | ||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Current assets | $ | $ | |||||
Net property, plant, and equipment | |||||||
Total assets | |||||||
Current liabilities | |||||||
Owners’ equity – non-controlling interest | $ | $ |
(7) | Fair Value of Derivative and Other Financial Instruments |
Economic Hedges | |||||||
June 30, 2019 | December 31, 2018 | ||||||
(In thousands) | |||||||
Other current assets | $ | $ | |||||
Other deferred charges | |||||||
Other current liabilities | ( | ) | ( | ) | |||
Other deferred credits | ( | ) | ( | ) | |||
( | ) | ( | ) | ||||
Net | $ | $ | ( | ) |
Economic Hedges | ||||||
MMBTU | MWh | |||||
June 30, 2019 | ( | ) | ||||
December 31, 2018 |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Equity securities: | |||||||||||||||
Net gains from equity securities sold | $ | $ | $ | $ | |||||||||||
Net gains (losses) from equity securities still held | ( | ) | ( | ) | |||||||||||
Total net gains on equity securities | |||||||||||||||
Available-for-sale debt securities: | |||||||||||||||
Net gains (losses) on debt securities | ( | ) | ( | ) | |||||||||||
Net gains (losses) on investment securities | $ | $ | ( | ) | $ | $ | ( | ) |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Proceeds from sales | $ | $ | $ | $ | |||||||||||
Gross realized gains | $ | $ | $ | $ | |||||||||||
Gross realized (losses) | $ | ( | ) | $ | ( | ) | $ | ( | ) | $ | ( | ) |
Fair Value | |||
(In thousands) | |||
Within 1 year | $ | ||
After 1 year through 5 years | |||
After 5 years through 10 years | |||
After 10 years through 15 years | |||
After 15 years through 20 years | |||
After 20 years | |||
$ |
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) | |||||||||||||||||||
June 30, 2019 | |||||||||||||||||||
Cash and cash equivalents | $ | $ | $ | $ | |||||||||||||||
Equity securities: | |||||||||||||||||||
Corporate stocks, common | |||||||||||||||||||
Corporate stocks, preferred | |||||||||||||||||||
Mutual funds and other | |||||||||||||||||||
Available-for-sale debt securities: | |||||||||||||||||||
U.S. Government | $ | ||||||||||||||||||
International Government | |||||||||||||||||||
Municipals | |||||||||||||||||||
Corporate and other | |||||||||||||||||||
$ | $ | $ | $ | $ | |||||||||||||||
Commodity derivative assets | $ | $ | $ | $ | |||||||||||||||
Commodity derivative liabilities | ( | ) | ( | ) | |||||||||||||||
Net | $ | $ | $ | $ | |||||||||||||||
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) | |||||||||||||||||||
December 31, 2018 | |||||||||||||||||||
Cash and cash equivalents | $ | $ | $ | $ | |||||||||||||||
Equity securities: | |||||||||||||||||||
Corporate stocks, common | |||||||||||||||||||
Corporate stocks, preferred | |||||||||||||||||||
Mutual funds and other | |||||||||||||||||||
Available-for-sale debt securities: | |||||||||||||||||||
U.S. Government | $ | ||||||||||||||||||
International Government | |||||||||||||||||||
Municipals | |||||||||||||||||||
Corporate and other | |||||||||||||||||||
$ | $ | $ | $ | $ | |||||||||||||||
Commodity derivative assets | $ | $ | $ | $ | |||||||||||||||
Commodity derivative liabilities | ( | ) | ( | ) | |||||||||||||||
Net | $ | ( | ) | $ | $ | ( | ) | $ |
Corporate Debt | |||
(In thousands) | |||
Balance at December 31, 2018 | $ | ||
Actual return on assets sold during the period | ( | ) | |
Actual return on assets still held at period end | |||
Purchases | |||
Sales | ( | ) | |
Balance at June 30, 2019 | $ | ||
Balance at December 31, 2017 | $ | ||
Actual return on assets sold during the period | ( | ) | |
Actual return on assets still held at period end | ( | ) | |
Purchases | |||
Sales | ( | ) | |
Balance at June 30, 2018 | $ |
GAAP Fair Value Hierarchy | |||||||||||||||||||
Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||||
June 30, 2019 | (In thousands) | ||||||||||||||||||
PNMR | $ | $ | $ | $ | $ | ||||||||||||||
PNM | $ | $ | $ | $ | $ | ||||||||||||||
TNMP | $ | $ | $ | $ | $ | ||||||||||||||
December 31, 2018 | |||||||||||||||||||
PNMR | $ | $ | $ | $ | $ | ||||||||||||||
PNM | $ | $ | $ | $ | $ | ||||||||||||||
TNMP | $ | $ | $ | $ | $ |
(8) | Stock-Based Compensation |
Six Months Ended June 30, | ||||||||
Restricted Shares and Performance Based Shares | 2019 | 2018 | ||||||
Expected quarterly dividends per share | $ | $ | ||||||
Risk-free interest rate | % | % | ||||||
Market-Based Shares | ||||||||
Dividend yield | % | % | ||||||
Expected volatility | % | % | ||||||
Risk-free interest rate | % | % |
Restricted Stock | Stock Options | ||||||||||||
Shares | Weighted- Average Grant Date Fair Value | Shares | Weighted- Average Exercise Price | ||||||||||
Outstanding at December 31, 2018 | $ | $ | |||||||||||
Granted | |||||||||||||
Exercised | ( | ) | ( | ) | |||||||||
Forfeited | |||||||||||||
Expired | |||||||||||||
Outstanding at June 30, 2019 | $ | $ |
Six Months Ended June 30, | ||||||||
Restricted Stock | 2019 | 2018 | ||||||
Weighted-average grant date fair value | $ | $ | ||||||
Total fair value of restricted shares that vested (in thousands) | $ | $ | ||||||
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) | $ | $ |
(9) | Financing |
Funding Date | Maturity Date | Principal Amount | Interest Rate | ||||||
(In millions) | |||||||||
March 29, 2019 | March 29, 2034 | $ | % | ||||||
March 29, 2019 | March 29, 2039 | % | |||||||
March 29, 2019 | March 29, 2044 | % | |||||||
July 1, 2019 | July 1, 2029 | % | |||||||
$ |
June 30, | December 31, | |||||||
Short-term Debt | 2019 | 2018 | ||||||
(In thousands) | ||||||||
PNM: | ||||||||
PNM Revolving Credit Facility | $ | $ | ||||||
PNM 2017 New Mexico Credit Facility | ||||||||
TNMP Revolving Credit Facility | ||||||||
PNMR: | ||||||||
PNMR Revolving Credit Facility | ||||||||
PNMR 2018 One-Year Term Loan | ||||||||
PNMR Development Revolving Credit Facility | ||||||||
$ | $ |
(10) | Pension and Other Postretirement Benefit Plans |
Three Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||
Service cost | $ | $ | $ | $ | $ | $ | |||||||||||||||||
Interest cost | |||||||||||||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||||||
Amortization of net (gain) loss | |||||||||||||||||||||||
Amortization of prior service cost | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||||||
Net Periodic Benefit Cost | $ | $ | $ | ( | ) | $ | ( | ) | $ | $ | |||||||||||||
Six Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||
Service cost | $ | $ | $ | $ | $ | $ | |||||||||||||||||
Interest cost | |||||||||||||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||||||
Amortization of net (gain) loss | |||||||||||||||||||||||
Amortization of prior service cost | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||||||
Net Periodic Benefit Cost | $ | $ | $ | ( | ) | $ | ( | ) | $ | $ |
Three Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||
Service cost | $ | $ | $ | $ | $ | $ | |||||||||||||||||
Interest cost | |||||||||||||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||||||
Amortization of net (gain) loss | ( | ) | ( | ) | |||||||||||||||||||
Amortization of prior service cost | |||||||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | ( | ) | $ | ( | ) | $ | ( | ) | $ | ( | ) | $ | $ | |||||||||
Six Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||||||||
Service cost | $ | $ | $ | $ | $ | $ | |||||||||||||||||
Interest cost | |||||||||||||||||||||||
Expected return on plan assets | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||||||
Amortization of net (gain) loss | ( | ) | ( | ) | |||||||||||||||||||
Amortization of prior service cost | |||||||||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | ( | ) | $ | ( | ) | $ | ( | ) | $ | ( | ) | $ | $ |
(11) | Commitments and Contingencies |
(12) | Regulatory and Rate Matters |
• | Inclusion of the January 2016 purchase of the assets underlying |
• | Recovery of annual rent expenses associated with the |
• | Disallowance of the recovery of any future contributions for PVNGS decommissioning costs related to the |
• | An increase in base non-fuel revenues totaling $ |
• | A ROE of |
• | 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 (Note 14) |
• | Disallowing PNM’s ability to collect an equity return on certain investments aggregating $ |
• | 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 |
• | A requirement to consider the prudency of PNM’s decision to continue its participation in Four Corners in a future proceeding |
• |
• | A PPA through 2044 for the output of New Mexico Wind, having a current aggregate capacity of |
• | A PPA through 2042 for the output of the Lightning Dock Geothermal facility; with a current capacity of |
• | Solar distributed generation, aggregating |
• | Solar and wind RECs as needed to meet the RPS requirements |
• | Casa Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC, which is located near House, New Mexico, has a total capacity of |
• | A |
• | 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 |
• |
Effective Date | Approved Increase in Rate Base | Annual Increase in Revenue | ||||
(In millions) | ||||||
March 14, 2017 | ||||||
September 13, 2017 | ||||||
March 27, 2018 | ||||||
March 21, 2019 |
(13) | Lease Commitments |
June 30, 2019 | January 1, 2019 | ||||||||||||||||||||||
PNM | TNMP | PNMR Consolidated | PNM | TNMP | PNMR Consolidated | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Operating leases: | |||||||||||||||||||||||
Operating lease assets, net of amortization | $ | $ | $ | $ | $ | $ | |||||||||||||||||
Current portion of operating lease liabilities | |||||||||||||||||||||||
Long-term portion of operating lease liabilities |
June 30, 2019 | |||||||||||
PNM | TNMP | PNMR Consolidated | |||||||||
(In thousands) | |||||||||||
Financing leases: | |||||||||||
Non-utility property | $ | $ | $ | ||||||||
Accumulated depreciation | ( | ) | ( | ) | ( | ) | |||||
Non-utility property, net | $ | $ | $ | ||||||||
Other current liabilities | $ | $ | $ | ||||||||
Other deferred credits |
June 30, 2019 | ||||||||
PNM | TNMP | PNMR Consolidated | ||||||
Weighted average remaining lease term (In years): | ||||||||
Operating leases | ||||||||
Financing leases | ||||||||
Weighted average discount rate: | ||||||||
Operating leases | % | % | % | |||||
Financing leases | % | % | % |
Three Months Ended June 30, 2019 | Six Months Ended June 30, 2019 | ||||||||||||||||||||||
PNM | TNMP | PNMR Consolidated | PNM | TNMP | PNMR Consolidated | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Operating lease cost: | $ | $ | $ | $ | $ | $ | |||||||||||||||||
Less: amounts capitalized | ( | ) | ( | ) | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||
Total operating lease expense | $ | $ | $ | $ | $ | $ | |||||||||||||||||
Financing lease cost: | |||||||||||||||||||||||
Amortization of right-of-use assets | |||||||||||||||||||||||
Interest on lease liabilities | |||||||||||||||||||||||
Less: amounts capitalized | ( | ) | ( | ) | ( | ) | ( | ) | ( | ) | ( | ) | |||||||||||
Total financing lease expense | |||||||||||||||||||||||
Variable lease expense | |||||||||||||||||||||||
Short-term lease expense | |||||||||||||||||||||||
Total lease expense for the period | $ | $ | $ | $ | $ | $ |
Six Months Ended June 30, 2019 | |||||||||||
PNM | TNMP | PNMR Consolidated | |||||||||
(In thousands) | |||||||||||
Cash paid for amounts included in the measurement of lease liabilities: | |||||||||||
Operating cash flows from operating leases | $ | $ | $ | ||||||||
Operating cash flows from financing leases | |||||||||||
Finance cash flows from financing leases | |||||||||||
Non-cash information related to right-of-use assets obtained in exchange for lease obligations: | |||||||||||
Operating leases | $ | $ | $ | ||||||||
Financing leases |
As of June 30, 2019 | |||||||||||||||||||||||
PNM | TNMP | PNMR Consolidated | |||||||||||||||||||||
Financing | Operating | Financing | Operating | Financing | Operating | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Remainder of 2019 | $ | $ | $ | $ | $ | $ | |||||||||||||||||
2020 | |||||||||||||||||||||||
2021 | |||||||||||||||||||||||
2022 | |||||||||||||||||||||||
2023 | |||||||||||||||||||||||
Later years | |||||||||||||||||||||||
Total minimum lease payments | |||||||||||||||||||||||
Less: Imputed interest | |||||||||||||||||||||||
Lease liabilities as of June 30, 2019 | $ | $ | $ | $ | $ | $ |
As of December 31, 2018 | |||||||||||
Operating leases | |||||||||||
PNM | TNMP | PNMR Consolidated | |||||||||
(In thousands) | |||||||||||
2019 | $ | $ | $ | ||||||||
2020 | |||||||||||
2021 | |||||||||||
2022 | |||||||||||
2023 | |||||||||||
Later years | |||||||||||
Total minimum lease payments | $ | $ | $ |
(14) | Income Taxes |
(15) | Related Party Transactions |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||||||
(In thousands) | |||||||||||||||
Services billings: | |||||||||||||||
PNMR to PNM | $ | $ | $ | $ | |||||||||||
PNMR to TNMP | |||||||||||||||
PNM to TNMP | |||||||||||||||
TNMP to PNMR | |||||||||||||||
PNMR to NMRD | |||||||||||||||
Renewable energy purchases: | |||||||||||||||
PNM from NMRD | |||||||||||||||
Interconnection billings: | |||||||||||||||
PNM to NMRD | |||||||||||||||
PNM to PNMR | |||||||||||||||
Interest billings: | |||||||||||||||
PNMR to PNM | |||||||||||||||
PNM to PNMR | |||||||||||||||
PNMR to TNMP | |||||||||||||||
Income tax sharing payments: | |||||||||||||||
PNMR to PNM | |||||||||||||||
TNMP to PNMR |
(16) | Goodwill |
• | Earning authorized returns on regulated businesses |
• | Delivering at or 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 transitioning to an emissions-free generating portfolio by 2040 |
• | 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 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 recovery of the costs associated with converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS; 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 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) |
• | A revenue increase totaling $10.3 million, which includes a reduction to reflect the impact of the decrease in the federal corporate income tax rate and updates to PNM’s cost of debt (aggregating an estimated $47.6 million annually) |
• | A ROE of 9.575% compared to the 10.125% requested by PNM |
• | 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 (Note 14) |
• | Disallowing PNM’s ability to collect an equity return on certain investments aggregating $148.1 million at Four Corners, but allowing recovery of 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 |
• | A decision to defer future consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to a future proceeding |
Approval Date | Percent Increase | ||
December 2015 | 10 | % | |
December 2016 | 10 | % | |
December 2017 | 9 | % | |
December 2018 | 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 Independent System Operator Western Energy Imbalance Market |
• | PNM should analyze its current Reeves 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 transitioning to a 100% emissions-free generating portfolio by 2040 |
• | Preparing PNM’s system to meet New Mexico’s increasing renewable energy requirements as cost-effectively as possible |
• | Increasing energy efficiency participation |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
(In millions, except per share amounts) | |||||||||||||||||||||||
Net earnings (loss) attributable to PNMR | $ | (75.9 | ) | $ | 38.2 | $ | (114.1 | ) | $ | (57.2 | ) | $ | 53.2 | $ | (110.4 | ) | |||||||
Average diluted common and common equivalent shares(1) | 79.9 | 80.0 | (0.1 | ) | 79.9 | 80.0 | (0.1 | ) | |||||||||||||||
Net earnings (loss) attributable to PNMR per diluted share | $ | (0.95 | ) | $ | 0.48 | $ | (1.43 | ) | $ | (0.72 | ) | $ | 0.67 | $ | (1.39 | ) |
Three Months Ended | Six Months Ended | ||||||
June 30, 2019 | June 30, 2019 | ||||||
(In millions) | |||||||
PNM | $ | (113.4 | ) | $ | (102.1 | ) | |
TNMP | (0.1 | ) | (5.4 | ) | |||
Corporate and Other | (0.5 | ) | (2.8 | ) | |||
Net change | $ | (114.1 | ) | $ | (110.4 | ) |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Electric operating revenues | $ | 238.2 | $ | 264.5 | $ | (26.3 | ) | $ | 507.5 | $ | 500.7 | $ | 6.8 | ||||||||||
Cost of energy | 58.9 | 66.4 | (7.5 | ) | 158.2 | 137.2 | 21.0 | ||||||||||||||||
Utility margin | 179.4 | 198.2 | (18.8 | ) | 349.3 | 363.6 | (14.3 | ) | |||||||||||||||
Operating expenses | 255.5 | 107.1 | 148.4 | 362.0 | 207.6 | 154.4 | |||||||||||||||||
Depreciation and amortization | 39.8 | 38.2 | 1.6 | 79.0 | 74.8 | 4.2 | |||||||||||||||||
Operating income (loss) | (116.0 | ) | 52.9 | (168.9 | ) | (91.7 | ) | 81.2 | (172.9 | ) | |||||||||||||
Other income (deductions) | 7.7 | 0.2 | 7.5 | 25.7 | 3.9 | 21.8 | |||||||||||||||||
Interest charges | (18.5 | ) | (20.0 | ) | 1.5 | (36.9 | ) | (40.8 | ) | 3.9 | |||||||||||||
Segment earnings (loss) before income taxes | (126.8 | ) | 33.1 | (159.9 | ) | (102.8 | ) | 44.3 | (147.1 | ) | |||||||||||||
Income (taxes) benefit | 43.5 | (2.3 | ) | 45.8 | 41.5 | (2.0 | ) | 43.5 | |||||||||||||||
Valencia non-controlling interest | (3.5 | ) | (4.1 | ) | 0.6 | (6.3 | ) | (7.8 | ) | 1.5 | |||||||||||||
Preferred stock dividend requirements | (0.1 | ) | (0.1 | ) | — | (0.3 | ) | (0.3 | ) | — | |||||||||||||
Segment earnings (loss) | $ | (86.9 | ) | $ | 26.5 | $ | (113.4 | ) | $ | (67.9 | ) | $ | 34.2 | $ | (102.1 | ) |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
Percentage | Percentage | ||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||
(Gigawatt hours, except customers) | |||||||||||||||||
Residential | 660.6 | 747.4 | (11.6 | )% | 1,456.2 | 1,499.1 | (2.9 | )% | |||||||||
Commercial | 933.7 | 1,017.1 | (8.2 | ) | 1,761.9 | 1,851.5 | (4.8 | ) | |||||||||
Industrial | 266.2 | 210.1 | 26.7 | 516.3 | 415.8 | 24.2 | |||||||||||
Public authority | 54.2 | 61.2 | (11.4 | ) | 103.8 | 111.5 | (6.9 | ) | |||||||||
Economy energy service (1) | 163.9 | 172.3 | (4.9 | ) | 320.8 | 343.0 | (6.5 | ) | |||||||||
Other sales for resale | 484.4 | 479.2 | 1.1 | 1,359.1 | 1,160.2 | 17.1 | |||||||||||
2,563.0 | 2,687.3 | (4.6 | )% | 5,518.1 | 5,381.1 | 2.5 | % | ||||||||||
Average retail customers (thousands) | 529.6 | 525.8 | 0.7 | % | 529.3 | 525.3 | 0.8 | % |
Three Months Ended June 30, 2019 | |||||
Change | |||||
Utility margin: | (In millions) | ||||
Rate relief – Additional revenue due to rate increase approved by the NMPRC effective February 1, 2018 (Note 12) | $ | 1.4 | |||
Retail customer usage/load – Weather normalized KWh sales decreased 1.3%, primarily due to decreased sales to commercial customers | (2.3 | ) | |||
Weather – Milder weather in 2019; cooling degree days were 52.8% lower in the second quarter | (14.2 | ) | |||
Transmission – Decrease due to lower revenues under formula transmission rates, partially offset by the addition of new customers | (1.8 | ) | |||
Rate riders – Includes renewable energy, fuel clause and energy efficiency riders | (1.2 | ) | |||
Other | (0.7 | ) | |||
Net Change | $ | (18.8 | ) |
Three Months Ended June 30, 2019 | |||||
Change | |||||
Operating expenses: | (In millions) | ||||
Higher plant maintenance costs at SJGS and gas-fired plants, partially offset by lower plant maintenance costs at Four Corners and PVNGS | $ | 1.1 | |||
Higher capitalized administrative and general expenses due to higher construction spending | (0.5 | ) | |||
Regulatory disallowance resulting from the NM Supreme Court’s May 2019 decision in PNM’s appeal of the NM 2015 Rate Case (Note 12) | 147.5 | ||||
Higher employee related, outside service, and vegetation management expenses | 2.1 | ||||
Other | (1.8 | ) | |||
Net Change | $ | 148.4 |
Depreciation and amortization: | |||||
Increased utility plant in service | $ | 1.3 | |||
Other | 0.3 | ||||
Net Change | $ | 1.6 |
Other income (deductions): | |||||
Higher gains on investment securities in the NDT and coal mine reclamation trusts | $ | 6.3 | |||
Higher interest income and lower trust expenses related to investment securities in the NDT and coal mine reclamation trusts | 1.8 | ||||
Other | (0.6 | ) | |||
Net Change | $ | 7.5 |
Three Months Ended June 30, 2019 | |||||
Change | |||||
Interest charges: | (In millions) | ||||
Lower interest on $350.0 million of SUNs refinanced in May 2018 | $ | 2.0 | |||
Lower interest on $100.0 million of SUNs refinanced in August 2018 | 0.8 | ||||
Lower debt AFUDC | (0.3 | ) | |||
Higher interest on term loan agreements | (0.7 | ) | |||
Interest on deposit by PNMR Development for potential transmission interconnections, which is offset in Corporate and Other (Note 9) | (0.3 | ) | |||
Net Change | $ | 1.5 |
Income taxes: | |||||
Lower segment earnings before income taxes | $ | 40.5 | |||
Amortization of excess deferred income taxes due to lower segment earnings before income taxes, excluding discrete items | (1.8 | ) | |||
Reversal of excess deferred income taxes resulting from regulatory disallowances in the NM 2015 Rate Case (Note 12) | 7.5 | ||||
Other | (0.4 | ) | |||
Net Change | $ | 45.8 |
Six Months Ended June 30, 2019 | |||||
Change | |||||
Utility margin: | (In millions) | ||||
Rate relief – Additional revenue due to rate increase approved by the NMPRC effective February 1, 2018 (Note 12) | $ | 3.1 | |||
Retail customer usage/load - Weather normalized KWh sales decreased 0.1% due to decreased sales to commercial customers, partially offset by increased sales to residential and industrial customers | (1.0 | ) | |||
Weather – Milder weather in 2019; cooling degree days were 52.8% lower in the second quarter, offset by colder weather in the first quarter | (11.2 | ) | |||
Transmission – Decrease due to lower revenues under formula transmission rates, partially offset by the addition of new customers | (0.6 | ) | |||
Rate riders – Includes renewable energy, fuel clause and energy efficiency riders | (4.0 | ) | |||
Other | (0.6 | ) | |||
Net Change | $ | (14.3 | ) |
Six Months Ended June 30, 2019 | |||||
Change | |||||
Operating expenses: | (In millions) | ||||
Higher plant maintenance costs at SJGS and gas-fired plants, partially offset by lower plant maintenance costs at Four Corners and PVNGS | $ | 0.8 | |||
Higher capitalized administrative and general expenses due to higher construction spending in 2019 | (0.7 | ) | |||
Accelerated recovery of SNCR technology on SJGS Units 1 and 4 | 0.3 | ||||
Regulatory disallowance resulting from the NM Supreme Court’s May 2019 decision in PNM’s appeal of the NM 2015 Rate Case (Note 12) | 148.8 | ||||
Higher employee related, outside service, and vegetation management expenses | 6.0 | ||||
Other | (0.8 | ) | |||
Net Change | $ | 154.4 |
Depreciation and amortization: | |||||
Increased utility plant in service | $ | 3.0 | |||
Higher depreciation resulting from amortization of stranded costs associated with the retirement of SJGS Units 2 and 3 | 0.5 | ||||
Other | 0.7 | ||||
Net Change | $ | 4.2 |
Other income (deductions): | |||||
Higher gains on investment securities in the NDT and coal mine reclamation trusts | $ | 20.0 | |||
Higher interest income and lower trust expenses related to investment securities in the NDT and coal mine reclamation trusts | 2.4 | ||||
Other | (0.6 | ) | |||
Net Change | $ | 21.8 |
Interest charges: | |||||
Lower interest on $350.0 million of SUNs refinanced in May 2018 | $ | 5.9 | |||
Lower interest on $100.0 million of SUNs refinanced in August 2018 | 1.6 | ||||
Lower debt AFUDC | (1.0 | ) | |||
Higher interest on term loan agreements | (1.4 | ) | |||
Interest on deposit by PNMR Development for potential transmission interconnections, which is offset in Corporate and Other (Note 9) | (1.2 | ) | |||
Net Change | $ | 3.9 |
Income taxes: | |||||
Lower segment earnings before income taxes | $ | 37.0 | |||
Amortization of excess deferred income taxes due to lower segment earnings before income taxes, excluding discrete items | (0.1 | ) | |||
Reversal of excess deferred income taxes resulting from regulatory disallowances in the NM 2015 Rate Case (Note 12) | 7.5 | ||||
Increase due to lower excess tax benefits related to stock compensation awards (Note 8) | (0.5 | ) | |||
Other | (0.4 | ) | |||
Net Change | $ | 43.5 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Electric operating revenues | $ | 92.0 | $ | 87.8 | $ | 4.2 | $ | 172.3 | $ | 169.4 | $ | 2.9 | |||||||||||
Cost of energy | 24.9 | 21.4 | 3.5 | 47.2 | 43.1 | 4.1 | |||||||||||||||||
Utility margin | 67.1 | 66.5 | 0.6 | 125.1 | 126.3 | (1.2 | ) | ||||||||||||||||
Operating expenses | 24.0 | 23.5 | 0.5 | 49.3 | 48.5 | 0.8 | |||||||||||||||||
Depreciation and amortization | 20.5 | 16.1 | 4.4 | 40.7 | 32.5 | 8.2 | |||||||||||||||||
Operating income | 22.6 | 26.8 | (4.2 | ) | 35.2 | 45.4 | (10.2 | ) | |||||||||||||||
Other income (deductions) | 0.7 | 0.8 | (0.1 | ) | 1.3 | 1.9 | (0.6 | ) | |||||||||||||||
Interest charges | (6.6 | ) | (7.8 | ) | 1.2 | (15.4 | ) | (15.5 | ) | 0.1 | |||||||||||||
Segment earnings before income taxes | 16.7 | 19.9 | (3.2 | ) | 21.1 | 31.7 | (10.6 | ) | |||||||||||||||
Income (taxes) | (1.5 | ) | (4.5 | ) | 3.0 | (1.8 | ) | (7.0 | ) | 5.2 | |||||||||||||
Segment earnings | $ | 15.3 | $ | 15.4 | $ | (0.1 | ) | $ | 19.4 | $ | 24.8 | $ | (5.4 | ) |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
Percentage | Percentage | ||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||
Volumetric load (1) (GWh) | |||||||||||||||||
Residential | 736.4 | 790.2 | (6.8 | )% | 1,355.1 | 1,447.0 | (6.4 | )% | |||||||||
Commercial and other | 7.6 | 7.9 | (3.8 | ) | 15.4 | 16.0 | (3.8 | ) | |||||||||
Total volumetric load | 744.0 | 798.1 | (6.8 | )% | 1,370.5 | 1,463.0 | (6.3 | )% | |||||||||
Demand-based load (2) (MW) | 4,587.5 | 4,342.7 | 5.6 | % | 9,309.5 | 8,652.9 | 7.6 | % | |||||||||
Average retail consumers (thousands) (3) | 255.0 | 251.2 | 1.5 | % | 254.4 | 250.6 | 1.5 | % |
Three Months Ended June 30, 2019 | |||||
Change | |||||
Utility margin: | (In millions) | ||||
Retail rate relief – TNMP 2018 Rate Case retail rate increase effective January 1, 2019, including integration of amounts previously recovered in the AMS rate rider and the impact of rate design changes between customer classes (Note 12) | $ | 1.3 | |||
Transmission rate relief - Increase in transmission cost of service rates primarily resulting from current year filings, net of changes resulting from the TNMP 2018 Rate Case (Note 12) | 0.8 | ||||
Retail customer usage/load – Weather normalized KWh sales decreased 0.9%; the average number of retail consumers increased 1.5% | (0.1 | ) | |||
Demand-based customer usage/load - Higher demand-based revenues for large commercial and industrial customers; billed demand excluding retail transmission customers increased 4.1%. | 0.7 | ||||
Weather – Milder weather in 2019; cooling degree days were 7.5% lower in 2019 resulting from warmer weather in 2018 | (1.1 | ) | |||
Rate Riders – Impacts of rate riders, including the CTC surcharge, energy efficiency rider, and transmission cost recovery factor | (1.0 | ) | |||
Net Change | $ | 0.6 |
Three Months Ended June 30, 2019 | |||||
Change | |||||
Operating expenses: | (In millions) | ||||
Higher employee related expenses | $ | 0.4 | |||
Higher property taxes due to increased utility plant in service | 0.1 | ||||
Net Change | $ | 0.5 |
Depreciation and amortization: | |||||
Increased utility plant in service | $ | 1.4 | |||
Higher depreciation rates approved in the TNMP 2018 Rate Case | 2.2 | ||||
Amortization of AMS and Hurricane Harvey regulatory assets approved in the TNMP 2018 Rate Case | 0.7 | ||||
Other | 0.1 | ||||
Net Change | $ | 4.4 |
Other income (deductions): | |||||
Higher equity AFUDC | $ | 0.2 | |||
Lower CIAC | (0.3 | ) | |||
Net Change | $ | (0.1 | ) |
Three Months Ended June 30, 2019 | |||||
Change | |||||
Interest charges: | (In millions) | ||||
Repayment of $172.3 million 9.50% first mortgage bonds in April 2019 (Note 9) | $ | 4.2 | |||
Issuance of $225.0 of long-term debt in March 2019 (Note 9) | (2.2 | ) | |||
Issuance of $60.0 million of long-term debt in June 2018 | (0.6 | ) | |||
Issuance of $20.0 million term loan in July 2018 and $15.0 million in December 2018 | (0.3 | ) | |||
Other | 0.1 | ||||
Net Change | $ | 1.2 |
Income taxes: | |||||
Lower segment earnings before income taxes | $ | 0.7 | |||
Amortization of excess deferred federal income taxes (Note 14) | 2.5 | ||||
Other | (0.2 | ) | |||
Net Change | $ | 3.0 |
Six Months Ended June 30, 2019 | |||||
Change | |||||
Utility margin: | (In millions) | ||||
Retail rate relief – TNMP 2018 Rate Case retail rate increase effective January 1, 2019, including integration of amounts previously recovered in the AMS rate rider and the impact of rate design changes between customer classes (Note 12) | $ | 2.5 | |||
Transmission rate relief - Decrease in transmission cost of service rates primarily resulting from the TNMP 2018 Rate Case offset by current year filings | (1.7 | ) | |||
Retail customer usage/load – Weather normalized KWh sales decreased 1.3%; the average number of retail consumers increased 1.5% | (0.5 | ) | |||
Demand-based customer usage/load - Higher demand-based revenues for large commercial and industrial customers; billed demand excluding retail transmission customers increased 3.7%. | 1.4 | ||||
Weather – Milder weather in 2019; heating degree days were 18.6% lower in January 2019 resulting from unusually cold weather in January 2018; the mind weather trend continued in the second quarter of 2019 and cooling degree days were 12.6% lower year-to-date in 2019 resulting from warmer weather in 2018 | (1.9 | ) | |||
Rate Riders – Impacts of rate riders, including the CTC surcharge, energy efficiency rider, and transmission cost recovery factor | (1.0 | ) | |||
Net Change | $ | (1.2 | ) |
Six Months Ended June 30, 2019 | |||||
Change | |||||
Operating expenses: | (In millions) | ||||
Higher employee related expenses | $ | 1.3 | |||
Higher capitalization of administrative and general expenses due to higher construction expenditures | (1.0 | ) | |||
Higher property taxes due to increased utility plant in service | 0.5 | ||||
Lower vegetation management expenses | (0.4 | ) | |||
Other | 0.4 | ||||
Net Change | $ | 0.8 |
Depreciation and amortization: | |||||
Increased utility plant in service | $ | 2.3 | |||
Higher depreciation rates approved in the TNMP 2018 Rate Case | 4.5 | ||||
Higher amortization of AMS and Hurricane Harvey regulatory assets approved in the TNMP 2018 Rate Case (Note 12) | 1.2 | ||||
Other | 0.2 | ||||
Net Change | $ | 8.2 |
Other income (deductions): | |||||
Lower equity AFUDC | $ | (0.1 | ) | ||
Lower CIAC | (0.5 | ) | |||
Net Change | $ | (0.6 | ) |
Interest charges: | |||||
Repayment of $172.3 million 9.50% first mortgage bonds in April 2019 (Note 9) | $ | 4.2 | |||
Issuance of $225.0 of long-term debt in March 2019 (Note 9) | (2.3 | ) | |||
Issuance of $60.0 million of long-term debt in June 2018 | (1.2 | ) | |||
Issuance of $20.0 million term loan in July 2018 and $15.0 million in December 2018 | (0.6 | ) | |||
Net Change | $ | 0.1 |
Income taxes: | |||||
Lower segment earnings before income taxes | $ | 2.2 | |||
Amortization of excess deferred federal income taxes (Note 14) | 3.2 | ||||
Other | (0.2 | ) | |||
Net Change | $ | 5.2 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2019 | 2018 | Change | 2019 | 2018 | Change | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Electric operating revenues | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
Cost of energy | — | — | — | — | — | — | |||||||||||||||||
Utility margin | — | — | — | — | — | — | |||||||||||||||||
Operating expenses | (5.5 | ) | (5.4 | ) | (0.1 | ) | (11.3 | ) | (10.4 | ) | (0.9 | ) | |||||||||||
Depreciation and amortization | 5.8 | 5.7 | 0.1 | 11.7 | 11.4 | 0.3 | |||||||||||||||||
Operating income (loss) | (0.2 | ) | (0.4 | ) | 0.2 | (0.4 | ) | (1.1 | ) | 0.7 | |||||||||||||
Other income (deductions) | (0.1 | ) | 0.5 | (0.6 | ) | (1.0 | ) | 2.2 | (3.2 | ) | |||||||||||||
Interest charges | (4.7 | ) | (5.5 | ) | 0.8 | (9.2 | ) | (10.0 | ) | 0.8 | |||||||||||||
Segment earnings (loss) before income taxes | (5.1 | ) | (5.4 | ) | 0.3 | (10.5 | ) | (8.9 | ) | (1.6 | ) | ||||||||||||
Income (taxes) benefit | 0.8 | 1.7 | (0.9 | ) | 1.9 | 3.0 | (1.1 | ) | |||||||||||||||
Segment earnings (loss) | $ | (4.2 | ) | $ | (3.7 | ) | $ | (0.5 | ) | $ | (8.6 | ) | $ | (5.8 | ) | $ | (2.8 | ) |
Three Months Ended June 30, 2019 | |||||
Change | |||||
Other income (deductions): | (In millions) | ||||
Decrease in interest income on the Westmoreland Loan | $ | (1.0 | ) | ||
Decrease in donations and other contributions | 0.4 | ||||
Net Change | $ | (0.6 | ) |
Interest charges: | |||||
Issuance of $90.0 million PNMR Development Term Loan in November 2018 | (0.8 | ) | |||
Higher short-term borrowings | (0.1 | ) | |||
Issuance of $50.0 million PNMR 2018 Two-Year Term Loan | (0.4 | ) | |||
Repayment of $100.0 million PNMR 2016 Two-Year Term Loan | 0.7 | ||||
Repayment of the BTMU Term Loan in May 2018 | 1.1 | ||||
Elimination of intercompany interest (Note 9) | 0.3 | ||||
Net Change | $ | 0.8 |
Income taxes: | |||||
Impact of difference in effective tax rates used by PNMR and its subsidiaries in the calculation of income taxes in interim periods | $ | (0.8 | ) | ||
Lower segment loss before income taxes | (0.1 | ) | |||
Net Change | $ | (0.9 | ) |
Six Months Ended June 30, 2019 | |||||
Change | |||||
Other income (deductions): | (In millions) | ||||
Decrease in interest income on the Westmoreland Loan | $ | (2.7 | ) | ||
Increase in donations and other contributions | (0.1 | ) | |||
Other | (0.4 | ) | |||
Net Change | $ | (3.2 | ) |
Interest charges: | |||||
Issuance of $300.0 million PNMR 2018 SUNs in March 2018 | $ | (1.8 | ) | ||
Issuance of $90.0 million PNMR Development Term Loan in November 2018 | (1.5 | ) | |||
Issuance of $50.0 million PNMR 2018 Two-Year Term Loan | (0.8 | ) | |||
Lower short-term borrowings | 0.3 | ||||
Repayment of $150.0 million PNMR 2015 Term Loan in March 2018 | 0.8 | ||||
Repayment of $100.0 million PNMR 2016 Two-Year Term Loan | 1.1 | ||||
Repayment of the BTMU Term Loan in May 2018 | 1.8 | ||||
Elimination of intercompany interest (Note 9) | 1.2 | ||||
Other | (0.3 | ) | |||
Net Change | $ | 0.8 |
Income taxes: | |||||
Impact of difference in effective tax rates used by PNMR and its subsidiaries in the calculation of income taxes in interim periods | $ | (1.7 | ) | ||
Larger segment loss before income taxes | 0.4 | ||||
Other | 0.2 | ||||
Net Change | $ | (1.1 | ) |
Six Months Ended June 30, | |||||||||||
2019 | 2018 | Change | |||||||||
(In millions) | |||||||||||
Net cash flows from: | |||||||||||
Operating activities | $ | 171.9 | $ | 133.9 | $ | 38.0 | |||||
Investing activities | (312.1 | ) | (200.3 | ) | (111.8 | ) | |||||
Financing activities | 142.4 | 67.3 | 75.1 | ||||||||
Net change in cash and cash equivalents | $ | 2.1 | $ | 0.9 | $ | 1.2 |
Six Months Ended June 30, | |||||||||||
2019 | 2018 | Change | |||||||||
Cash (Outflows) for Utility Plant Additions | (In millions) | ||||||||||
PNM: | |||||||||||
Generation | $ | (36.3 | ) | $ | (35.8 | ) | $ | (0.5 | ) | ||
Renewables | (31.7 | ) | — | (31.7 | ) | ||||||
Transmission and distribution | (78.2 | ) | (63.7 | ) | (14.5 | ) | |||||
Four Corners SCRs | — | (6.9 | ) | 6.9 | |||||||
Nuclear fuel | (11.7 | ) | (13.9 | ) | 2.2 | ||||||
(157.9 | ) | (120.3 | ) | (37.6 | ) | ||||||
TNMP: | |||||||||||
Transmission | (47.1 | ) | (51.2 | ) | 4.1 | ||||||
Distribution | (77.3 | ) | (64.2 | ) | (13.1 | ) | |||||
(124.4 | ) | (115.4 | ) | (9.0 | ) | ||||||
Corporate and Other: | |||||||||||
Computer hardware and software | (10.8 | ) | (9.9 | ) | (0.9 | ) | |||||
Total cash (outflows) for additions to utility plant | $ | (293.1 | ) | $ | (245.6 | ) | $ | (47.5 | ) | ||
Other Cash Flows from Investing Activities | |||||||||||
Proceeds from sales of investment securities | $ | 234.0 | $ | 794.1 | $ | (560.1 | ) | ||||
Purchases of investment securities | (239.6 | ) | (797.3 | ) | 557.7 | ||||||
Principal payments on the Westmoreland Loan | — | 56.6 | (56.6 | ) | |||||||
Investments in NMRD | (13.3 | ) | (8.0 | ) | (5.3 | ) | |||||
Other, net | (0.1 | ) | (0.1 | ) | — | ||||||
Total cash (outflows) from investing activities | $ | (312.1 | ) | $ | (200.3 | ) | $ | (111.8 | ) |
• | Short-term borrowings increased $106.5 million in 2019 compared to a decrease of $22.8 million in 2018, resulting in a net increase in cash flows from financing activities of $129.3 million |
• | In 2019, PNM borrowed $250.0 million under the PNM 2019 Term Loan and used the proceeds to repay the $200.0 million PNM 2017 Term Loan |
• | In 2019, TNMP issued $225.0 million of TNMP 2019 Bonds used the proceeds to repay TNMP’s $172.3 million 9.50% first mortgage bonds |
• | In 2018, PNMR issued $300.0 million aggregate principal amount of 3.250% SUNs and used the proceeds to repay the $150.0 million PNMR 2015 Term Loan Agreement and to reduce short-term borrowings |
• | In 2018, PNM issued $350.0 million of SUNs and repaid $350.0 million of 7.95% of SUNs |
• | NM Capital made principal payments on the BTMU Term Loan Agreement of $50.1 million in 2018 |
• | In 2018, TNMP issued $60.0 million of 3.85% first mortgage bonds and used the proceeds to reduce short-term debt |
• | 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 and replacing generation resources, including expenditures for compliance with environmental requirements and for renewable energy resources |
• | Expanding the electric transmission and distribution systems |
• | Purchasing nuclear fuel |
2019 | 2020-2023 | Total | |||||||||
(In millions) | |||||||||||
Construction expenditures | $ | 605.2 | $ | 2,913.4 | $ | 3,518.6 | |||||
Capital contributions to NMRD | 29.9 | 33.6 | 63.5 | ||||||||
Dividends on PNMR common stock | 92.4 | 369.6 | 462.0 | ||||||||
Dividends on PNM preferred stock | 0.5 | 2.1 | 2.6 | ||||||||
Total capital requirements | $ | 728.0 | $ | 3,318.7 | $ | 4,046.7 |
Three Months Ended June 30, 2019 | Six Months Ended June 30, 2019 | |||||||||||||||
Range of Borrowings | Low | High | Low | High | ||||||||||||
(In millions) | ||||||||||||||||
PNM: | ||||||||||||||||
PNM Revolving Credit Facility | $ | — | $ | 27.2 | $ | — | $ | 40.0 | ||||||||
PNM 2017 New Mexico Credit Facility | — | 15.0 | — | 15.0 | ||||||||||||
TNMP Revolving Credit Facility | 7.5 | 55.0 | — | 55.0 | ||||||||||||
PNMR Revolving Credit Facility | 50.8 | 84.5 | 20.0 | 84.5 | ||||||||||||
PNMR Development Revolving Credit Facility | 11.6 | 21.9 | 6.0 | 21.9 |
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 | PNMR Consolidated | |||||||||||||||
(In millions) | |||||||||||||||||||
Financing capacity: | |||||||||||||||||||
Revolving credit facility | $ | 400.0 | $ | 75.0 | $ | 300.0 | $ | 40.0 | $ | 815.0 | |||||||||
PNM 2017 New Mexico Credit Facility | 40.0 | — | — | — | 40.0 | ||||||||||||||
Total financing capacity | $ | 440.0 | $ | 75.0 | $ | 300.0 | $ | 40.0 | $ | 855.0 | |||||||||
Amounts outstanding as of July 26, 2019: | |||||||||||||||||||
Revolving credit facility | $ | 29.4 | $ | — | $ | 67.7 | $ | 32.9 | $ | 130.0 | |||||||||
PNM 2017 New Mexico Credit Facility | 25.0 | — | — | — | 25.0 | ||||||||||||||
Letters of credit | 2.5 | 0.1 | 4.7 | — | 7.3 | ||||||||||||||
Total short-term debt and letters of credit | 56.9 | 0.1 | 72.4 | 32.9 | 162.3 | ||||||||||||||
Remaining availability as of July 26, 2019 | $ | 383.1 | $ | 74.9 | $ | 227.6 | $ | 7.1 | $ | 692.7 | |||||||||
Invested cash as of July 26, 2019 | $ | — | $ | 13.8 | $ | 0.9 | $ | — | $ | 14.7 |
June 30, 2019 | December 31, 2018 | ||||
PNMR | |||||
PNMR common equity | 36.7 | % | 38.6 | % | |
Preferred stock of subsidiary | 0.3 | 0.3 | |||
Long-term debt | 63.0 | 61.1 | |||
Total capitalization | 100.0 | % | 100.0 | % | |
PNM | |||||
PNM common equity | 43.8 | % | 45.6 | % | |
Preferred stock | 0.4 | 0.4 | |||
Long-term debt | 55.8 | 54.0 | |||
Total capitalization | 100.0 | % | 100.0 | % | |
TNMP | |||||
Common equity | 52.0 | % | 53.9 | % | |
Long-term debt | 48.0 | 46.1 | |||
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, the NM Supreme Court’s decisions in the appeal of that order, the NM 2016 Rate Case and related deferral of the issue of the prudence of PNM’s decision to continue participation in Four Corners to PNM’s next general rate case and recovery of PNM’s investments in that plant, any actions resulting from PNM’s SJGS Abandonment Application, which requests NMPRC approval to retire PNM’s share of SJGS in 2022 and for recovery of undepreciated investments and other costs associated with the retirement, the evaluation of that application under the recently enacted ETA, and/or the conclusions reached in PNM’s 2017 IRP (collectively, the “Regulatory Proceedings”) 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 of the Regulatory Proceedings and supporting forecasts utilized in future test year rate proceedings |
• | Uncertainty regarding what actions PNM may take with respect to the generating capacity in PVNGS Units 1 and 2 that is under lease at the expiration of the lease terms in 2023 and 2024, or upon the occurrence of certain specific events, as well as the related treatment for ratemaking purposes by the NMPRC |
• | 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, the outcome of PNM’s SJGS Abandonment Application, including the impacts of the recently enacted ETA, the results of PNM’s 2017 IRP filing, which indicates that PNM’s customers would benefit from PNM’s exit from Four Corners in 2031, including regulatory recovery of undepreciated investments and other costs in the event the NMPRC orders generating facilities be retired |
• | 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 ultimate outcomes of the Regulatory Proceedings |
• | The impacts on the electricity usage of customers and consumers due to performance of state, regional, and national economies, energy efficiency measures, weather, seasonality, alternative sources of power, advances in technology, and other changes in supply and demand |
• | 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 outcomes of the Regulatory Proceedings |
• | The risks associated with completion of generation, transmission, distribution, and other projects |
• | The potential unavailability of cash from PNMR’s subsidiaries due to regulatory, statutory, or contractual restrictions or subsidiary earnings or cash flows |
• | The performance of generating units, transmission systems, and distribution systems, which could be negatively affected by operational issues, fuel quality and supply issues, unplanned outages, extreme weather conditions, wildfires, terrorism, cybersecurity breaches, and other catastrophic events, as well the costs the Company may incur to repair its facilities and/or the liabilities the Company may incur to third parties in connection with such issues |
• | State and federal regulation or legislation relating to environmental matters and renewable energy requirements, 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, and taxes, including guidance related to the Tax Act, 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, including the impacts of the recently enacted ETA |
• | 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 |
• | Regulatory, financial, and operational risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainties |
• | The risk that FERC rulemakings or lack of additional capacity during peak hours may negatively impact the operation of PNM’s transmission system |
• | The impacts of decreases in the values of marketable securities maintained in trusts to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits, including potential increased volatility resulting from international developments |
• | Uncertainty surrounding counterparty performance and credit risk, including the ability of counterparties to supply fuel and perform reclamation activities and impacts to financial support provided to facilitate the coal supply at SJGS |
• | The effectiveness of risk management regarding commodity transactions and counterparty risk |
• | The outcome of legal proceedings, including the extent of insurance coverage |
• | Changes in applicable accounting principles or policies |
• | 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 |
Six Months Ended | |||||||
June 30, | |||||||
2019 | 2018 | ||||||
Economic Hedges | (In thousands) | ||||||
Sources of fair value gain (loss): | |||||||
Net fair value at beginning of period | $ | (94 | ) | $ | (94 | ) | |
Amount realized on contracts delivered during period | 56 | 54 | |||||
Changes in fair value | — | 2 | |||||
Net mark-to-market change recorded in earnings | 56 | 56 | |||||
Net change recorded as regulatory assets and liabilities | 60 | (284 | ) | ||||
Net fair value at end of period | $ | 22 | $ | (322 | ) |
Schedule of Credit Risk Exposure | |||||||||
June 30, 2019 | |||||||||
Rating (1) | Credit Risk Exposure(2) | Number of Counter-parties >10% | Net Exposure of Counter-parties >10% | ||||||
(Dollars in thousands) | |||||||||
External ratings: | |||||||||
Investment grade | $ | 3,138 | 2 | $ | 2,206 | ||||
Non-investment grade | — | — | — | ||||||
Split ratings | — | — | — | ||||||
Internal ratings: | |||||||||
Investment grade | 1,106 | 1 | 594 | ||||||
Non-investment grade | — | — | — | ||||||
Total | $ | 4,244 | $ | 2,800 |
(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 the Tri-State hazard sharing agreement), forward sales, and short-term sales. The gross exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by posted credit collateral. At June 30, 2019, PNMR held $0.9 million of cash collateral to offset its credit exposure. |
• | The Clean Air Act – Regional Haze – NEE Complaint |
• | The Clean Air Act – Regional Haze – Four Corners – Four Corners Federal Agency Lawsuit |
• | Navajo Nation Environmental Issues |
• | Santa Fe Generating Station |
• | Continuous Highwall Mining Royalty Rate |
• | PVNGS Water Supply Litigation |
• | San Juan River Adjudication |
• | Rights-of-Way Matter |
• | Navajo Nations Allottee Matters |
• | PNM – New Mexico General Rate Cases |
• | PNM – Renewable Portfolio Standard |
• | PNM – Integrated Resource Plans |
• | PNM – SJGS Abandonment Application |
• | PNM – Facebook, Inc. Data Center Project |
• | PNM – Application For a New 345 kV Transmission Line |
• | PNM – Western Spirit Line |
• | TNMP – Transmission Cost of Service Rates |
• | TNMP – Energy Efficiency |
3.1 | PNMR | |
3.2 | PNM | |
3.3 | TNMP | |
3.4 | PNMR | |
3.5 | PNM | |
3.6 | TNMP | |
10.1 | PNM | |
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 - The instance document does not appear in the interactive data file because XBRL tags are embedded within the Inline XBRL document |
101.SCH | PNMR, PNM, and TNMP | Inline XBRL Taxonomy Extension Schema Document |
101.CAL | PNMR, PNM, and TNMP | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF | PNMR, PNM, and TNMP | Inline XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB | PNMR, PNM, and TNMP | Inline XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | PNMR, PNM, and TNMP | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
104 | PNMR, PNM, and TNMP | Cover Page Inline XBRL File (included in Exhibits 101) |
PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY | ||
(Registrants) | ||
Date: | August 2, 2019 | /s/ Joseph D. Tarry |
Joseph D. Tarry | ||
Vice President, Controller and Treasurer | ||
(Officer duly authorized to sign this report) |
1. | I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
a) | All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | August 2, 2019 | 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: | August 2, 2019 | 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: | August 2, 2019 | 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: | August 2, 2019 | 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: | August 2, 2019 | 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: | August 2, 2019 | 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: | August 2, 2019 | 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: | August 2, 2019 | 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: | August 2, 2019 | 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 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
|
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
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 | $ 634,405 | $ 64 | $ 504,166 | $ 130,175 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings (loss) before subsidiary preferred stock dividends | 61,248 | 53,462 | 53,462 | 7,786 | 42,296 | 34,510 | 34,510 | 7,786 | ||||||||
Net earnings | 34,510 | 24,779 | 24,779 | |||||||||||||
Total other comprehensive income | 3,391 | 3,391 | 3,391 | 1,592 | 1,592 | 1,592 | ||||||||||
Subsidiary preferred stock dividends | (264) | (264) | (264) | |||||||||||||
Dividends declared on preferred stock | (264) | (264) | (264) | |||||||||||||
Dividends declared on common stock | (21,108) | (21,108) | (21,108) | (10,436) | (10,436) | |||||||||||
Proceeds from stock option exercise | 924 | 924 | 924 | |||||||||||||
Awards of common stock | (12,268) | (12,268) | (12,268) | |||||||||||||
Stock based compensation expense | 3,325 | 3,325 | 3,325 | |||||||||||||
Valencia’s transactions with its owner | (8,381) | (8,381) | (8,381) | (8,381) | ||||||||||||
Ending balance at Jun. 30, 2018 | 1,788,315 | 1,722,715 | 1,149,646 | (103,757) | 676,826 | 65,600 | 1,523,612 | 1,458,012 | 1,264,918 | (106,709) | 299,803 | 65,600 | ||||
Ending balance TNMP at Jun. 30, 2018 | 648,748 | 64 | 504,166 | 144,518 | ||||||||||||
Beginning 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 | ||||
Beginning balance TNMP at Mar. 31, 2018 | 642,794 | 64 | 504,166 | 138,564 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings (loss) before subsidiary preferred stock dividends | 42,449 | 38,340 | 38,340 | 4,109 | 30,781 | 26,673 | 26,673 | 4,108 | ||||||||
Net earnings | 26,672 | 15,367 | 15,367 | |||||||||||||
Total other comprehensive income | 1,763 | 1,763 | 1,763 | 1,310 | 1,310 | 1,310 | ||||||||||
Subsidiary preferred stock dividends | (132) | (132) | (132) | |||||||||||||
Dividends declared on preferred stock | (132) | (132) | (132) | |||||||||||||
Dividends declared on common stock | (9,413) | (9,413) | ||||||||||||||
Proceeds from stock option exercise | 122 | 122 | 122 | |||||||||||||
Awards of common stock | (1,423) | (1,423) | (1,423) | |||||||||||||
Stock based compensation expense | 431 | 431 | 431 | |||||||||||||
Valencia’s transactions with its owner | (3,909) | (3,909) | (3,908) | (3,908) | ||||||||||||
Ending balance at Jun. 30, 2018 | 1,788,315 | 1,722,715 | 1,149,646 | (103,757) | 676,826 | 65,600 | 1,523,612 | 1,458,012 | 1,264,918 | (106,709) | 299,803 | 65,600 | ||||
Ending balance TNMP at Jun. 30, 2018 | 648,748 | 64 | 504,166 | 144,518 | ||||||||||||
Beginning balance at Dec. 31, 2018 | 1,752,594 | 1,688,382 | 1,153,113 | (108,684) | 643,953 | 64,212 | 1,461,571 | 1,397,359 | 1,264,918 | (110,422) | 242,863 | 64,212 | ||||
Beginning balance TNMP at Dec. 31, 2018 | 1,688,382 | 1,397,359 | 674,093 | 64 | 534,166 | 139,863 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings (loss) before subsidiary preferred stock dividends | (50,622) | (56,950) | (56,950) | 6,328 | (61,340) | (67,668) | (67,668) | 6,328 | ||||||||
Net earnings | (67,668) | 19,365 | 19,365 | |||||||||||||
Total other comprehensive income | 8,502 | 8,502 | 8,502 | 10,474 | 10,474 | 10,474 | ||||||||||
Subsidiary preferred stock dividends | (264) | (264) | (264) | |||||||||||||
Dividends declared on preferred stock | (264) | (264) | (264) | |||||||||||||
Dividends declared on common stock | (23,099) | (23,099) | (23,099) | (14,811) | (14,811) | |||||||||||
Proceeds from stock option exercise | 943 | 943 | 943 | |||||||||||||
Awards of common stock | (9,892) | (9,892) | (9,892) | |||||||||||||
Stock based compensation expense | 4,526 | 4,526 | 4,526 | |||||||||||||
Valencia’s transactions with its owner | (7,948) | (7,948) | (7,948) | (7,948) | ||||||||||||
Ending balance at Jun. 30, 2019 | 1,674,740 | 1,612,148 | 1,148,690 | (100,182) | 563,640 | 62,592 | 1,402,493 | 1,339,901 | 1,264,918 | (99,948) | 174,931 | 62,592 | ||||
Ending balance TNMP at Jun. 30, 2019 | 1,612,148 | 1,339,901 | 678,647 | 64 | 534,166 | 144,417 | ||||||||||
Beginning balance at Mar. 31, 2019 | 1,747,458 | 1,684,679 | 1,148,364 | (103,239) | 639,554 | 62,779 | 1,485,307 | 1,422,528 | 1,264,918 | (104,265) | 261,875 | 62,779 | ||||
Beginning balance TNMP at Mar. 31, 2019 | 667,478 | 64 | 534,166 | 133,248 | ||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||
Net earnings (loss) before subsidiary preferred stock dividends | (72,283) | (75,782) | (75,782) | 3,499 | (83,313) | (86,812) | (86,812) | 3,499 | ||||||||
Net earnings | (86,812) | 15,267 | 15,267 | |||||||||||||
Total other comprehensive income | 3,057 | 3,057 | 3,057 | 4,317 | 4,317 | 4,317 | ||||||||||
Subsidiary preferred stock dividends | (132) | (132) | (132) | |||||||||||||
Dividends declared on preferred stock | (132) | (132) | (132) | |||||||||||||
Dividends declared on common stock | (4,098) | (4,098) | ||||||||||||||
Proceeds from stock option exercise | 13 | 13 | 13 | |||||||||||||
Awards of common stock | (956) | (956) | (956) | |||||||||||||
Stock based compensation expense | 1,269 | 1,269 | 1,269 | |||||||||||||
Valencia’s transactions with its owner | (3,686) | (3,686) | (3,686) | (3,686) | ||||||||||||
Ending balance at Jun. 30, 2019 | 1,674,740 | $ 1,612,148 | $ 1,148,690 | $ (100,182) | $ 563,640 | $ 62,592 | 1,402,493 | $ 1,339,901 | $ 1,264,918 | $ (99,948) | $ 174,931 | $ 62,592 | ||||
Ending balance TNMP at Jun. 30, 2019 | $ 1,612,148 | $ 1,339,901 | $ 678,647 | $ 64 | $ 534,166 | $ 144,417 |
Significant Accounting Policies and Responsibility for Financial Statements |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Significant Accounting Policies and Responsibility for Financial Statements | Significant Accounting Policies and Responsibility for Financial Statements Financial Statement Preparation In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at June 30, 2019 and December 31, 2018, and the consolidated results of operations and comprehensive income for the three and six months ended June 30, 2019 and 2018, and cash flows for the six months ended June 30, 2019 and 2018. 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 2018 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2019 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 2018 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, equity transactions, and interconnection billings (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. This has historically resulted in dividends attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.290 per share in July 2019 and $0.265 per share in July 2018, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings. TNMP declared and paid cash dividends on common stock to PNMR of $4.1 million and $14.8 million in the three and six months ended June 30, 2019 and $9.4 million and $10.4 million in the three and six months ended June 30, 2018. Investment in NM Renewable Development, LLC As discussed in Note 1 of the 2018 Annual Reports on Form 10-K, PNMR Development and AEP OnSite Partners created NMRD in September 2017 to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. NMRD’s current renewable energy capacity in operation is 33.9 MW. In July 2019, NMRD entered into agreements to provide power from 1.2 MW of solar-PV facilities, which are expected to be placed in commercial operation in the second half of 2019, to the City of Rio Rancho, New Mexico. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. The investment in NMRD is accounted for using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations. In the six months ended June 30, 2019 and 2018, PNMR Development made cash contributions of $13.3 million and $8.0 million to NMRD to be used primarily for its construction activities. On July 22, 2019, PNMR Development made an additional cash contribution to NMRD of $11.0 million. PNMR presents its share of net earnings from NMRD in other income on the Condensed Consolidated Statements of Earnings. Summarized financial information for NMRD is as follows:
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 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. In November 2018, the FASB clarified that receivables arising from operating leases are not within the scope of Topic 326 for assets measured at amortized costs. Instead, impairments of receivables arising from operating leases should be accounted for in accordance with Topic 842. In May 2019, the FASB issued transition relief by providing an option to irrevocably elect the fair value option for certain financial assets previously measured at amortized cost. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date. 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 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 9 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other postretirement benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures. Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on December 31, 2020, although early adoption is permitted, and requires retrospective application. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14 but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures. Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard. Accounting Standards Update 2018-18 – Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 In November 2018, the FASB issued ASU 2018-18 to clarify transactions between collaborative arrangement participants that should be recognized as revenue under Topic 606. ASU 2018-18 is effective for the Company on January 1, 2020, although early adoption is permitted, and requires retrospective application. The Company has collaborative arrangements related to its interests in SJGS, Four Corners, PVNGS, and Luna. The Company believes its current accounting practices comply with the requirements of ASU 2018-18 but is in the process of analyzing the impacts of the new standard.
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. Eliminations of intercompany income and expense transactions are reflected in the Corporate and Other segment. The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION
The Company defines utility margin as electric operating revenues less cost of energy. Cost of energy consists primarily of fuel and purchase power costs for PNM and costs charged by third-party transmission providers for TNMP. The Company believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all such costs are offset in revenues as fuel and purchase power costs are passed through to customers under PNM’s FPPAC and third-party transmission costs are passed on to customers through TNMP’s transmission cost recovery factor. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.
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Accumulated Other Comprehensive Income (Loss) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2019 and 2018 is as follows:
The Condensed Consolidated Statements of Earnings include pre-tax amounts reclassified from AOCI related to Unrealized Gains on Available-for-Sale Securities in gains (losses) on investment securities, related to Pension Liability Adjustment in other (deductions), and related to Fair Value Adjustment for Cash Flow Hedges in interest charges. The income tax impacts of all amounts reclassified from AOCI are included in income taxes in the Condensed Consolidated Statements of Earnings.
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Earnings Per Share |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share | Earnings Per Share In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows:
(1) Due to the loss in the three and six months ended June 30, 2019, no potentially dilutive shares are reflected in the average number of shares used to compute net earnings (loss) per share of common stock since any impact would be anti-dilutive. At June 30, 2019, PNMR’s potentially dilutive shares consist of stock options and restricted stock (see Note 8).
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Electric Operating Revenues |
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Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. Additional information concerning electric operating revenue is contained in Note 4 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Disaggregation of Revenues A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects alternative revenue program revenues (“ARP”) and other revenues.
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 ARPs. For PNM, accounts receivable reflected on the Condensed Consolidated Balance Sheets, net of allowance for uncollectible accounts, includes $52.7 million at June 30, 2019 and $61.7 million at December 31, 2018 resulting from contracts with customers. All of TNMP’s accounts receivable results from contracts with customers. Contract assets are an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). The Company has no contract assets as of June 30, 2019 or December 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 Open Access Transmission Tariff, 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 the capacity rights have been reserved, which is generally over one year. 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 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 10 of the Notes to Consolidated Financial Statements in the 2018 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 and six months ended June 30, 2019, PNM paid $5.0 million and $9.9 million for fixed charges and $0.2 million and $0.3 million for variable charges. For the three and six months ended June 30, 2018, PNM paid $4.9 million and $9.8 million for fixed charges and $0.6 million and $0.9 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:
Westmoreland San Juan Mining, LLC As discussed in the subheading Coal Supply in Note 11, PNM purchases coal for SJGS under a coal supply agreement (“SJGS CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland Coal Company (“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 purchase of SJCC. On May 22, 2018, the full principal outstanding under the Westmoreland Loan was repaid. NM Capital used a portion of the proceeds to repay all remaining amounts owed under the BTMU Term Loan. These payments effectively terminated the loan agreements and PNMR’s guarantee of NM Capital’s obligations under the BTMU Term Loan. Prior to its repayment, the Westmoreland Loan resulted in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital were subject to possible loss in the event of default of WSJ. On October 9, 2018, Westmoreland filed a Current Report on Form 8-K with the SEC announcing it had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. On March 15, 2019, Westmoreland emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, the assets of SJCC were sold to Westmoreland San Juan Mining, LLC (“WSJ LLC”), a subsidiary of Westmoreland Mining Holdings, LLC. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of WSJ including obligations to PNM under the SJGS CSA and to PNMR under a letter of credit support agreement. See (Note 11). PNMR issued $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. As discussed above, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR for the letters of credit. The letters of credit support results in PNMR being considered to have a variable interest in WSJ LLC since PNMR is subject to possible loss in the event performance by PNMR is required under the letters of credit support. 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 WSJ LLC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the SJGS CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the SJGS CSA. In addition, each of the SJGS participants has established and funds a trust to meet its future reclamation obligations. |
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 9 of the Notes to Consolidated Financial Statements in the 2018 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. 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. PNM has 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 and Tri-State have a hazard sharing agreement, which expires on May 31, 2022. Under this agreement, each party sells the other party 100 MW of capacity and energy from a designated generation resource on a unit contingent basis, subject to certain performance guarantees. Both the purchases and sales are made at the same market index price. This agreement serves to reduce the magnitude of each party’s single largest generating hazard and assists in enhancing the reliability and efficiency of their respective operations. PNM passes the sales and purchases through to customers under PNM’s FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. 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 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 six months ended June 30, 2019 and the year ended December 31, 2018, 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 presented in the following line items on the Condensed Consolidated Balance Sheets:
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 $3.1 million at June 30, 2019 and $3.6 million at December 31, 2018 resulting 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 June 30, 2019 and December 31, 2018, PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at June 30, 2019 and December 31, 2018, amounts posted as cash collateral under margin arrangements were $0.5 million and $1.0 million. At June 30, 2019 and December 31, 2018, obligations to return cash collateral were $0.9 million and $1.0 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. There were insignificant amounts hedged under this plan as of June 30, 2019 and no amounts were hedged under this plan as of December 31, 2018. The effects of mark-to-market commodity derivative instruments on PNM’s revenues and cost of energy during the three and six months ended June 30, 2019 and 2018 were less than $0.1 million. 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 June 30, 2019 and December 31, 2018, PNM had no such contracts in a net 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 June 30, 2019 and December 31, 2018, the fair value of investment securities included $318.8 million and $287.1 million for the NDT and $44.0 million and $41.1 million for the mine reclamation trusts. As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, on January 1, 2018 the Company adopted Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10). Accordingly, 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. Under ASU 2016-01, the accounting for available-for-sale debt securities remains essentially unchanged. 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 $(0.8) million and $2.6 for the three and six months ended June 30, 2019 and $(2.6) million and $(3.8) million for the three and six months ended June 30, 2018.
The Company has no available-for-sale 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 June 30, 2019, the available-for-sale debt securities held by PNM, 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 six months ended June 30, 2019 or the year ended December 31, 2018. 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. 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. 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 debt securities.
A reconciliation of the changes in Level 3 fair value measurements is as follows:
The carrying amounts and fair values of long-term debt, which is not recorded at fair value on the Condensed Consolidated Balance Sheets, are presented below:
The carrying amount and fair value of the Company’s other investments presented on the Condensed Consolidated Balance Sheets are not material and not shown in the above table.
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Stock-Based Compensation |
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Share-based Payment Arrangement [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. The Company has not awarded stock options since 2010. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2018 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 June 30, 2019, PNMR had unrecognized expense related to stock awards of $6.0 million, which is expected to be recognized over an average of 1.73 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 operating cash flows when used to reduce income taxes payable. 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. The number of performance shares that ultimately vest cannot be determined until after the performance period ends. 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 six months ended June 30, 2019:
PNMR’s stock-based compensation program provides for performance and market targets through 2021. In February 2019, the Board approved amendments to exclude certain impacts of the Tax Act on performance metrics for the performance periods ending in 2018 and 2019. These amendments did not impact the Company’s calculation of grant date fair values under the plans, but did increase actual achievement levels for the performance period ending in 2018 from below “threshold” levels to below “target” levels and anticipated achievement levels for the performance period ending in 2019 from below “target” levels to the “maximum” level. Included as granted and exercised in the table above are 47,279 previously awarded shares that were earned for the 2016 through 2018 performance measurement period and ratified by the Board in February 2019 (based upon achieving market targets at below “threshold” levels, weighted at 40%, and performance targets at above “target” levels, together weighted at 60%). Excluded from the table above are maximums of 130,302, 146,941, and 135,678 shares for the three-year performance periods ending in 2019, 2020, and 2021 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible. 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 17,953 shares in February 2018. 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 June 30, 2019, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $0.1 million with a weighted-average remaining contract life of 0.7 years. At June 30, 2019, 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 contain a single financial covenant that requires the maintenance of a debt-to-capitalization ratio. For the PNMR and PNMR Development agreements this ratio must be maintained at less than or equal to 70%, and for the PNM and TNMP agreements this ratio must be maintained at less than or equal to 65%. The Company’s revolving credit facilities and term loans generally also contain 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 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Financing Activities 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 was required to post in connection with permits relating to the operation of the San Juan mine. On March 15, 2019, WSJ LLC acquired the assets of SJCC following the bankruptcy of Westmoreland. WSJ LLC assumed the obligations to PNMR under the letters of credit support (Note 11). On April 9, 2018, PNMR Development deposited $68.2 million with PNM related to potential transmission network interconnections, which was classified as a cash inflow from financing activities on PNM’s Condensed Consolidated Statements of Cash Flows in the six months ended June 30, 2018. PNM used the deposit to repay intercompany borrowings. PNM is required to pay interest to PNMR Development to the extent work under the interconnections has not been performed. During the three and six months ended June 30, 2019 PNM recognized $1.0 million and $1.9 million of interest expense under the agreement. During the three and six months ended June 30, 2018, PNM recognized $0.7 million of interest expense under the agreement. At June 30, 2019, PNM’s remaining obligation under the interconnection agreement with PNMR Development of $68.2 million, excluding unpaid interest, is reflected in other deferred credits on PNM’s Condensed Consolidated Balance Sheets. As required by GAAP, all intercompany transactions related to this deposit have been eliminated on PNMR’s Condensed Consolidated Financial Statements. On January 18, 2019, PNM entered into a $250.0 million term loan agreement (the “PNM 2019 Term Loan”) among PNM, the lenders identified therein, and U.S. Bank N.A., as administrative agent. PNM used the proceeds of the PNM 2019 Term Loan to repay the PNM 2017 Term Loan, to reduce short-term borrowings under the PNM Revolving Credit Facility, and for general corporate purposes. The PNM 2019 Term Loan bears interest at a variable rate and must be repaid on or before July 17, 2020. On February 26, 2019, TNMP entered into the TNMP 2019 Bond Purchase Agreement with institutional investors for the sale of $305.0 million aggregate principal amount of four series of TNMP first mortgage bonds (the “TNMP 2019 Bonds”) offered in private placement transactions. TNMP issued $225.0 million of TNMP 2019 Bonds on March 29, 2019 and used the proceeds to repay TNMP’s $172.3 million 9.50% first mortgage bonds at their maturity on April 1, 2019, as well as to repay borrowings under the TNMP Revolving Credit Facility and for general corporate purposes. TNMP issued the remaining $80.0 million of TNMP 2019 Bonds on July 1, 2019 and used the proceeds to repay borrowings under the TNMP Revolving Credit Facility and for general corporate purposes. The TNMP 2019 Bonds are subject to continuing compliance with the representations, warranties and covenants of the TNMP 2019 Bond Purchase Agreement. The terms of the TNMP 2019 Bond Purchase Agreement include customary covenants, including a covenant that requires TNMP to maintain a debt-to-capitalization ratio of less than or equal to 65%, customary events of default, a cross-default provision, and a change-of-control provision. TNMP will have the right to redeem any or all of the TNMP 2019 Bonds prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, borrowings under the $172.3 million 9.50% TNMP first mortgage bonds are reflected as being long-term in the Condensed Consolidated Balance Sheets at December 31, 2018 since TNMP demonstrated its intent and ability to re-finance the agreement on a long-term basis. Information concerning the funding dates, maturities and interest rates on the TNMP 2019 Bonds is as follows:
At June 30, 2019, variable interest rates were 3.20% on the $50.0 million PNMR 2018 Two-Year Term Loan, which matures in December 2020, 3.05% on the $250.0 million PNM 2019 Term Loan, which matures in July 2020, 3.10% on the $35.0 million TNMP 2018 Term Loan, which matures in July 2020, and 3.20% on the $90.0 million PNMR Development Term Loan, which matures in November 2020. See discussion of PNM’s SJGS Abandonment Application in Note 12, which includes a request to issue approximately $361 million of energy transition bonds, as provided by the ETA, upon the proposed retirement of SJGS in 2022. Short-term Debt and Liquidity The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. Both facilities currently expire on October 22, 2023 but contain options to be extended through October 2024, subject to approval by a majority of the lenders. 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 22, 2019, PNMR Development amended its $24.5 million revolving credit facility to increase the capacity to $25.0 million and to extend the term until February 24, 2020. On July 22, 2019, the PNMR Development Revolving Credit Facility was amended to increase the capacity to $40.0 million with the option to further increase the capacity to $50.0 million upon 15-days advance notice. The facility will continue to have the expiration date of February 24, 2020. The PNMR Development Revolving Credit Facility bears interest at a variable rate and contains terms similar to the PNMR Revolving Credit Facility. PNMR has guaranteed the obligations of PNMR Development under the facility. PNMR Development uses the facility to finance its participation in NMRD and for other activities. Short-term debt outstanding consisted of:
At June 30, 2019, the weighted average interest rate was 3.67% for the PNMR Revolving Credit Facility, 3.15% for the PNMR 2018 One-Year Term Loan, 3.53% for the PNM Revolving Credit Facility, 3.52% for the PNM 2017 New Mexico Credit Facility, 3.16% for the TNMP Revolving Credit Facility, and 3.41% for the PNMR Development Revolving Credit Facility. In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $4.7 million, $2.5 million, and $0.7 million at June 30, 2019 that reduce the available capacity under their respective revolving credit facilities. The above table excludes intercompany debt. As of June 30, 2019 and December 31, 2018, TNMP had $1.6 million and $0.1 million of intercompany borrowings from PNMR, PNM had zero and $19.8 million of intercompany borrowings from PNMR, and PNMR Development had $0.2 million and $0.5 million of intercompany borrowings from PNMR. In 2017, PNMR entered into three separate four-year hedging agreements whereby it effectively established fixed interest rates of 1.926%, 1.823%, and 1.629%, plus customary spreads over LIBOR for three separate tranches, each of $50.0 million, of its variable rate debt. These hedge agreements are accounted for as cash flow hedges and had fair values of $(0.4) million and less than $0.1 million at June 30, 2019 that are included in other current liabilities and other deferred charges on the Condensed Consolidated Balance Sheets. At December 31, 2018, the hedge agreements had fair values aggregating $1.0 million that are included in other current assets on the Condensed Consolidated Balance Sheets. As discussed in Note 3, changes in the fair value of the cash flow hedge are deferred in AOCI and amounts reclassified to the Condensed Consolidated Statement of Earnings are recorded in interest charges. 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. On January 1, 2019, the Company adopted Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. Adoption of the updated standard did not have a significant impact on these cash flow hedges. At July 26, 2019, PNMR, PNM, TNMP, and PNMR Development had availability of $227.6 million, $368.1 million, $74.9 million, and $7.1 million under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $15.0 million of availability under the PNM 2017 New Mexico Credit Facility. Total availability at July 26, 2019, on a consolidated basis, was $692.7 million for PNMR. As of July 26, 2019, PNM and TNMP had no borrowings from PNMR under their intercompany loan agreements. As of July 26, 2019, PNMR Development had $0.2 million of intercompany borrowings from PNMR. At July 26, 2019, PNMR, PNM, and TNMP had invested cash of $0.9 million, zero, and $13.8 million. The Company’s debt arrangements have various maturities and expiration dates. The $150.0 million PNMR 2018 One-Year Term Loan will mature in December 2019. PNM has $100.3 million of long-term debt that must be repriced by June 2020 and the $250.0 million PNM 2019 Term Loan matures in July 2020. In addition, the $35.0 million TNMP 2018 Term Loan matures in July 2020. The Company has no other long-term debt due through August 31, 2020. Additional information on debt maturities is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K.
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Pension and Other Postretirement Benefit Plans |
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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. In accordance with GAAP, the Company presents the service cost component of its net periodic benefit costs in administrative and general expenses and the non-service costs components in other income (deductions), net of amounts capitalized or deferred to regulatory assets and liabilities, on the Condensed Consolidated Statements of Earnings. PNM and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of accumulated 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 11 of the Notes to Consolidated Financial Statements in the 2018 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. 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 six months ended June 30, 2019 and 2018 and does not anticipate making any contributions to the pension plan in 2019-2021, but expects to contribute $1.3 million in 2022 and $22.9 million in 2023, based on current law, funding requirements, and estimates of portfolio performance. The funding assumptions were developed using discount rates of 4.2% to 4.6%. 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. Disbursements allocated to the OPEB trust, a portion of which are funded by PNM and considered to be contributions to the OPEB plan, were $0.7 million and $1.5 million in the three and six months ended June 30, 2019. However, PNM made no contributions to the OPEB trust in the three and six months ended June 30, 2018. Although PNM does not expect to make any contributions to the OPEB trust in 2019-2023, disbursements attributable to the OPEB plan that are expected to be funded by PNM are estimated to be $3.7 million in 2019 and $13.7 million for 2020-2023. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $0.7 million in the three and six months ended June 30, 2019 and $0.4 million and $0.9 million in the three and six months ended June 30, 2018 and are expected to total $1.5 million during 2019 and $5.6 million for 2020-2023. TNMP Plans The following table presents the components of the TNMP Plans’ net periodic benefit cost:
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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. In addition, the Company 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 proceedings in the normal course of its business (Note 12). 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 2018 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 that establishes a process for the payment of claims for costs incurred through 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 June 30, 2019 and December 31, 2018, PNM had a liability for interim storage costs of $12.7 million and $12.4 million, which is included in other deferred credits. PVNGS has sufficient capacity at its on-site Independent Spent Fuel Storage Installation (“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. The Energy Transition Act On March 22, 2019, the Governor signed into New Mexico state law Senate Bill 489, known as the Energy Transition Act (“ETA”). The ETA became effective as of June 14, 2019 and sets a statewide standard that requires investor-owned electric utilities to have specified percentages of their electric-generating portfolios be provided from renewable and zero-carbon generating resources. Prior to the enactment of the ETA, the REA established a mandatory RPS requiring utilities to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also amends sections of the REA to allow for the recovery of undepreciated investments and decommissioning costs related to qualifying EGUs that the NMPRC has required be removed from retail jurisdictional rates, provided replacement resources to be included in retail rates have lower or zero-carbon emissions. The ETA requires the NMPRC to review and approve utilities’ annual renewable portfolio plans to ensure compliance with the RPS. The ETA also directs the New Mexico Environmental Improvement Board to adopt standards of performance that limit CO2 emissions to no more than 1,100 lbs. per MWh beginning January 1, 2023 for new or existing coal-fired EGUs with original installed capacities exceeding 300 MW. The ETA provides for a transition from fossil-fuel generation resources to renewable and other carbon-free resources through certain provisions relating to the abandonment of coal-fired generating facilities. These provisions include the use of “energy transition bonds,” which are designed to be highly rated bonds that can be issued to finance certain costs of abandoning coal-fired facilities that are retired prior to January 1, 2023 for facilities operated by a “qualifying utility,” or prior to January 1, 2032 for facilities that are not operated by the qualifying utility. The amount of energy transition bonds that can be issued to recover abandonment costs is limited to the lesser of $375.0 million or 150% of the undepreciated investment of the facility as of the abandonment date. Proceeds provided by energy transition bonds must be used only for purposes related to providing utility service to customers and to pay “financing costs” (as defined by the ETA). These costs may include plant decommissioning and coal mine reclamation costs provided those costs have not previously been recovered from customers or disallowed by the NMPRC or by a court order. See Note 12 for a discussion of the NM Supreme Court’s decision to affirm the NMPRC’s disallowance of certain costs, including the cost of BDT at SJGS, in PNM’s NM 2015 Rate Case. Proceeds from energy transition bonds may also be used to fund severances for employees of the retired facility and related coal mine and to promote economic development, education and job training in areas impacted by the retirement of the coal-fired facilities. Energy transition bonds must be issued under an NMPRC approved financing order, are secured by “energy transition property,” are non-recourse to the issuing utility, and must be repaid by a non-bypassable charge paid by all customers of the issuing utility. These customer charges are subject to an adjustment mechanism designed to provide for timely and complete payment of principal and interest due under the energy transition bonds. The ETA also provides that utilities must obtain NMPRC approval of competitively procured replacement resources. In determining whether to approve replacement resources, the NMPRC must give preference to resources with the least environmental impacts, those with higher ratios of capital costs to fuel costs, and those located in the school district of the abandoned facility able to reduce the cost of reclamation and use for lands previously mined within the county of the EGU to be abandoned. The ETA also provides for the procurement of energy storage facilities and gives utilities discretion to maintain and control these systems to ensure reliable and efficient service. PNM expects the ETA will have a significant impact on PNM’s future generation portfolio, including PNM’s planned retirement of SJGS in 2022. See additional discussion in Note 12 of PNM’s SJGS Abandonment Application. PNM cannot predict the full impact of the ETA or the outcome of its pending and potential future generating resource abandonment and replacement resource filings with the NMPRC. 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 December 20, 2018, EPA released a new guidance document on tracking visibility progress for the second planning period. EPA is allowing states discretion to develop SIPs that may differ from EPA’s guidance as long as they are consistent with the CAA and other applicable regulations. SIPs for the second compliance period are due in July 2021. EPA’s decision to revisit the 2017 rule is not a determination on the merits of the issues raised in the petitions. PNM is evaluating the potential impacts of these matters. SJGS December 2018 Compliance Filing – As discussed in Note 16 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in December 2015 PNM received NMPRC approval for a plan to comply with the EPA regional haze rule at SJGS. Among other things, the NMPRC’s December 2015 order required that, no later than December 31, 2018, PNM make a filing with the NMRPC to determine the extent to which SJGS should continue serving PNM’s customers’ needs after June 30, 2022 (the “December 2018 Compliance Filing”). The December 2018 Compliance Filing was required to be made before PNM entered into a binding commitment for post-2022 coal supply but after PNM received firm pricing and other terms for the supply of coal at SJGS, unless PNM did not intend to pursue an agreement for post-2022 coal supply at SJGS. The NMPRC’s December 2015 order also indicated that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM is prohibited from recovering the undepreciated investment of its 132 MW interest and required that PNM’s 65 MW interest in SJGS Unit 4 be treated as excluded merchant plant. PNM is currently depreciating its investments in SJGS through 2053, which reflects the period of time over which the NMPRC has authorized PNM to recover its investment in SJGS from New Mexico retail customers. PNM submitted the December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in PNM’s 2017 IRP, PNM’s customers would benefit from the retirement of PNM’s share of SJGS after the current SJGS CSA expires in mid-2022 (Note 12). The December 2018 Compliance Filing also indicated that, pursuant to the terms of the agreements governing SJGS, all of the SJGS owners except for Farmington provided written notice that they do not intend to extend the SJGS operating agreements beyond their June 30, 2022 expiration dates, and that PNM has provided written notice to SJCC that PNM does not intend to extend the SJGS CSA beyond June 30, 2022. On January 30, 2019, the NMPRC issued an order initiating a proceeding and requiring PNM to submit an application for the abandonment of PNM’s share of SJGS by March 1, 2019. PNM filed a motion requesting the NMPRC vacate the January 30, 2019 order, which was deemed denied. On February 27, 2019, PNM filed a petition with the NM Supreme Court stating that the requirements of the January 30, 2019 order exceed the NMPRC’s authority by, among other things, mandating PNM to make a filing that is legally voluntary, and that the order is contrary to NMPRC precedent which requires abandonment applications to also include identified replacement resources and other information that would not be available to PNM by March 1, 2019. On March 1, 2019, the NM Supreme Court granted a temporary stay of the NMPRC’s order. Various parties intervened in the petition. On June 26, 2019, the NM Supreme Court lifted the stay, denied PNM’s petition without discussion, and vacated oral arguments that had been scheduled for July 9, 2019. See additional discussion of PNM’s July 1, 2019 SJGS Abandonment Application in Note 12. GAAP requires that long-lived assets be tested for impairment when events or changes in circumstances indicate that their carrying value may not be recoverable. As of December 31, 2018, PNM evaluated the events surrounding its future participation in SJGS and determined that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, PNM performed an impairment analysis that assumed SJGS would not continue to operate through 2053, as previously approved by the NMPRC. PNM’s impairment analysis indicated that, pursuant to the NMPRC’s December 2015 order, PNM’s undepreciated 132 MW interest in SJGS Unit 4 at June 30, 2022 will not be recovered from customers; that the estimated future cash flows expected to result from the operation of SJGS Unit 4 through June 30, 2022 are not sufficient to provide for recovery of PNM’s 65 MW merchant interest in the facility; and that it is unlikely PNM will be able to sell or transfer its interests in SJGS to third parties at amounts sufficient to provide for their recovery. As a result, as of December 31, 2018, PNM recorded a pre-tax impairment of its investment in SJGS of approximately $35.0 million, which is reflected as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings in the 2018 Annual Reports on Form 10-K. This amount includes the entire $11.9 million carrying value of PNM’s 65 MW interest in SJGS Unit 4 as of December 31, 2018 and $23.1 million of estimated undepreciated investments in PNM’s 132 MW jurisdictional interest as of June 30, 2022 that will not be recovered from customers. As of June 30, 2019 and December 31, 2018, the net book value of PNM’s investments in SJGS are $364.6 million and $373.6 million. See additional discussion below regarding the increase in PNM’s estimated liability for coal mine reclamation. NEE Complaint – On March 31, 2016, NEE filed a complaint with the NMPRC alleging that PNM failed to comply with its discovery obligation in the case authorizing the shutdown of SJGS Units 2 and 3 and requesting the NMPRC investigate whether financing provided by NM Capital to the former owner of SJCC (the “Westmoreland Loan”) could adversely affect PNM’s ability to provide electric service to its retail customers. On January 31, 2018, NEE filed a motion asking the NMPRC to investigate whether PNM’s relationship with the former owner of SJCC could be harmful to PNM’s customers. On May 23, 2018, PNM filed its response to the NMPRC staff’s comments noting that the Westmoreland Loan was paid in full on May 22, 2018. On October 11, 2018, PNM notified the NMPRC that the former owner of SJCC, Westmoreland, had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. As discussed in Note 6, on March 15, 2019, Westmoreland announced that it had emerged from Chapter 11 bankruptcy as a privately held company owned and operated by a group of its former creditors. Under the reorganization, all the assets of SJCC were sold to WSJ LLC. As successor entity to SJCC, WSJ LLC assumed all rights and obligations of Westmoreland including obligations to PNM under the SJGS CSA. The NMPRC has taken no further action on NEE’s complaints. PNM cannot predict if the NMPRC will take any further action on these matters or the potential outcome. 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 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 dismissal in the United States Court of Appeals for the Ninth Circuit on November 9, 2017, and the court granted their subsequent motion to expedite the appeal. Oral arguments for the appeal were held on March 7, 2019. On July 29, 2019, the Ninth Circuit issued a decision affirming the District Court’s dismissal of the case. PNM cannot predict if parties to the lawsuit will appeal this decision. Carbon Dioxide Emissions On August 3, 2015, EPA established standards to limit CO2 emissions from power plants. EPA took three separate but related actions in which it: (1) established the carbon pollution standards for new, modified, and reconstructed power plants; (2) established the 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 was being re-evaluated, which was granted. On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order put 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 directed the EPA Administrator to review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance Standards (“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 directed 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 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 proposed a legal interpretation concluding that the Clean Power Plan exceeded EPA’s statutory authority. On August 31, 2018, EPA published a proposed rule, informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. On June 19, 2019, EPA released the final version of the Affordable Clean Energy rule. EPA takes three actions in the final rule: (1) finalizes the repeal of the Clean Power Plan; (2) finalizes the Affordable Clean Energy rule; and (3) revises the implementing regulations for all emission guidelines issued under Clean Air Act Section 111(d), which among other things, extends the timing of state plans. The final rule is very similar to the August 2018 proposed rule. EPA set the Best System of Emissions Reduction (“BSER”) for existing coal-fired power plants as heat rate efficiency improvements based on a range of "candidate technologies" that can be applied inside the fence-line. Rather than setting a specific numerical standard of performance, EPA's rule directs states to determine which of the candidate technologies to apply to each coal-fired unit and establish standards of performance based on the degree of emission reduction achievable based on the application of BSER. States will have three years from when the rule is finalized to submit a plan to EPA and then the EPA has one year to approve the plan. If states do not submit a plan or their submitted plan is not acceptable, EPA will have two years to develop a federal plan. While corresponding NSR reform regulations were proposed as part of the EPA’s Affordable Clean Energy proposal, the final rule did not include such reform measures. EPA announced that it will be taking final action on the NSR reform proposal for EGUs in the near future. The Affordable Clean Energy rule is not expected to impact SJGS since EPA’s final approval of a state SIP would occur after the planned shutdown of SJGS in 2022 (subject to NMPRC approval). Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the Affordable Clean Energy rule on the Navajo Nation. PNM is currently reviewing the requirements of the Affordable Clean Energy rule and is unable to predict the potential financial or operational impacts on Four Corners. On December 20, 2018, EPA published in the Federal Register a proposed rule that would revise the carbon pollution standards rule published in October 2015 for fossil fueled power plants. The proposed rule would revise the standards for coal- fired units based on a revised BSER determination that would result in less stringent CO2 emission performance standards for new, reconstructed, and modified fossil-fueled power plants. EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. Comments on the proposal were due on March 18, 2019. PNM’s review of the GHG emission reductions standards under the Affordable Clean Energy rule and the revised proposed carbon pollution standards rule is ongoing. The Affordable Clean Energy rule has been challenged by several parties and may be impacted by further litigation. As discussed above, SJGS and Four Corners may also be required to comply with additional GHG restrictions issued by the New Mexico Environmental Improvement Board pursuant to the recently enacted ETA. 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 reasonably anticipated to endanger public health or welfare. 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 standard while retaining the annual standards for NOx and SO2 and the 24-hour SO2 standard. EPA also updated the final particulate matter standard in 2012 and updated the ozone standard in 2015. NOx Standard – On April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO2 is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO2 standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018. SO2 Standard – On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO2 NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO2 sources to identify maximum 1-hour SO2 concentrations. This characterization would result in these areas being designated as attainment, nonattainment, or unclassifiable 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 imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO2 emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required, among other things, that EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule by December 2020. 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 its formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO2 standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO2 emissions. On February 25, 2019, EPA announced its final decision to retain without changes the primary health-based NAAQS for SOx. Specifically, EPA will retain the current 1-hour standard for SO2, which is 75 parts per billion (“ppb”), based on the 3-year average of the 99th percentile of daily maximum 1-hour SO2 concentrations. SO2 is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS. On 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 required the installation of SNCRs. The revised permit also required the reduction of SO2 emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These reductions help SJGS meet the NAAQS for these constituents. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities at SJGS. See a discussion of the regulatory treatment of BDT in Note 12. Ozone Standard – On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 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 since these are the pollutants that form ground-level ozone, 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 more stringent ozone NAAQS final rule since western states like New Mexico and Arizona are 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 for ozone, which states used to determine their initial designation recommendations by October 1, 2016. NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016 and recommended designation of a small area in southern Dona Ana County as non-attainment for ozone. During 2017 and 2018, EPA released rules establishing area designations. In those rules, San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable and a small area in Dona Ana County, New Mexico is designated as marginal non-attainment. The final rule also establishes the timing of attainment dates for each non-attainment area classification, which are marginal, moderate, serious, severe, or extreme. The rule became effective May 8, 2018. Attainment plans are due mid-2021 to 2022. NMED has responsibility for bringing the small area in Dona County designated as marginal/non-attainment for ozone into compliance and will look at all sources of NOx and volatile organic compounds. NMED is working on the State Implementation Plan revision that outlines the strategies and emissions control measures that are expected to improve air quality in the area by May 8, 2021. These strategies and measures would aim to reduce the amount of NOx and volatile organic compounds emitted to the atmosphere and will rely upon current or upcoming federal rules, new or revised state rules, and other programs. PNM does not believe there will be material impacts to its facilities as a result of NMED’s non-attainment 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, PNM 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. In 2016, OSM filed a Motion for Voluntary Remand to allow the agency to conduct a new environmental analysis and 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. The public scoping process, data submittal phase, and public comment period was completed in July 2018. The Notice of Availability for the final EIS was published in the Federal Register and became available on the OSM website on March 15, 2019. NEPA requires OSM to identify a preferred alternative in the final EIS and prepare a recommendation to the Assistant Secretary of Land and Minerals Management. OSM has selected a plan that would allow for continued mining that would extend beyond 2022 as the preferred alternative based on the impact analysis in the EIS. On May 1, 2019, OSM published its Record of Decision, which would allow for continued mining in the underground mine in annual quantities similar to those being currently being provided. The OSM’s Record of Decision is subject to additional review and approval. PNM cannot predict the outcome of this matter. Navajo Nation Environmental Issues Four Corners is located on the Navajo Nation and is held under easements granted by the federal government, as well as agreements with the Navajo Nation which grant each of the owners the right to operate on the site. 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 In 2014, EPA issued a rule establishing 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). 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. The permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority. The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is working with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS. On May 23, 2018, several environmental groups sued EPA Region IX in the United States Court of Appeals for the Ninth Circuit Court over EPA’s failure to timely reissue the Four Corners NPDES permit. The petitioners asked the court to issue a writ of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit on June 12, 2018. The permit did not contain conditions related to the cooling water intake structure rule as EPA determined that the facility has achieved BTA for both impingement and entrainment by operating a closed-cycle recirculation system and no additional conditions are necessary. On July 16, 2018, several environmental groups filed a petition for review with the EPA’s Environmental Appeals Board concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning certain revised effluent limitation guidelines, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. On December 19, 2018, EPA withdrew the Four Corners NPDES permit in order to examine issues raised by the environmental groups. Withdrawal of the permit moots the appeal pending before the Environmental Appeals Board. The EPA’s Environmental Appeals Board thereafter dismissed the environmental groups’ appeal. EPA has issued a proposed NPDES permit for Four Corners and has indicated that it would accept comments through July 2019. As part of the proposal, EPA is contemplating a December 31, 2023 compliance deadline. EPA currently projects that it will take final action on the permit proposal by September 30, 2019. Four Corners will continue to operate under the 2001 NPDES permit. PNM cannot predict the outcome of this matter or whether reconsideration will have a material impact on PNM’s financial position, results of operations or cash flows. 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 or revised NPDES permit. On September 18, 2017, EPA published a final rule for postponement of certain compliance dates, which have not yet passed for the Effluent Limitations Guidelines rule. The 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, although the new deadlines have been challenged in court. The Effluent Limitations Guidelines rule was challenged in the U.S. Court of Appeals for the Fifth Circuit by numerous parties. On April 12, 2017, EPA signed a notice indicating its intent to reconsider portions of the rule and, on August 22, 2017, the Fifth Circuit issued an order severing the issues under reconsideration and holding the case in abeyance as to those issues. However, the court allowed challenges to other portions of the rule to proceed. On April 12, 2019, the Fifth Circuit granted those challenges and issued an opinion vacating several portions of the rule, specifically those related to legacy wastewater and leachate, for which the court deemed the standards selected by the EPA arbitrary and capricious. Because SJGS is zero discharge for wastewater and is not required to hold a NPDES permit, it is expected that minimal to no requirements will be imposed. Reeves Station, a PNM-owned gas-fired generating station, discharges cooling tower blowdown to a publicly owned treatment plant and holds an NPDES permit. It is expected that minimal to no requirements will be imposed at Reeves Station. EPA reissued an NPDES permit for Four Corners on June 12, 2018. EPA had determined that the guidelines in the 2015 rule were not applicable to this permit because the effective dates of the 2015 effluent guidelines rule were extended but later withdrew the Four Corners NPDES permit in order to examine issues raised by several environmental groups. Four Corners will continue to operate under the 2001 NPDES permit. See Cooling Water Intake Structures above. Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques during the next NPDES permit renewal for Four Corners, which will be in 2023. PNM is unable to predict the outcome of these matters or a range of the potential costs of compliance. Santa Fe Generating Station PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well. The Superfund Oversight Section of the NMED also has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. Results of tests conducted by NMED in April 2012 and April 2013 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property. This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. However, it is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels. Therefore, PNM has agreed to monitor nitrate levels in a limited number of wells under the terms of a renewed discharge permit for the former generating station. The renewed discharge permit requires that PNM conduct more frequent monitoring than originally anticipated, which resulted in an insignificant increase to the project cost estimate as of December 31, 2018. 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 continues to work with the Petroleum Storage Tank Bureau to monitor contaminants at the site. Qualified costs of this work are eligible for payment through the CAF. On March 28, 2019, PNM received notice from NMED that an abatement plan is required with respect to the site to address concentrations of previously identified compounds, unrelated to those disclosed above, found in the groundwater. The abatement plan would include an investigation to define site conditions and provide data necessary to select and design an abatement option. PNM submitted its abatement plan proposal to NMED on July 11, 2019. Under NMED regulations, NMED and PNM are required to publish information summarizing the source and magnitude of the pollution. NMED may also hold a public hearing if there is sufficient public interest. PNM is unable to predict the outcome of these matters. Coal Combustion Residuals Waste Disposal CCRs consisting of fly ash, bottom ash, and gypsum generated from coal combustion and emission control equipment at SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCR impoundments or landfills. The NMMMD currently regulates mine reclamation activities at the San Juan mine, including placement of CCRs in the surface mine pits, with federal oversight by the OSM. APS disposes of CCRs in ponds and dry storage areas at Four Corners. Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office. EPA’s final coal ash rule, which became effective on October 19, 2015, included a non-hazardous waste determination for coal ash. The rule sets minimum criteria for existing and new CCR landfills and surface impoundments. Because the rule is promulgated under Subtitle D of RCRA, it does not require regulated facilities to obtain permits, does not require states to adopt and implement the rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the requirements. On December 16, 2016, the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”) was signed into law to address critical water infrastructure needs in the United States. The WIIN Act contains a number of provisions requiring EPA to modify the self-implementing provisions of the current CCR rules under Subtitle D. Among other things, the WIIN Act provides for the establishment of state and EPA permit programs for CCRs, provides flexibility for states to incorporate the EPA final rule for CCRs 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 CCR rule is no longer self-implementing and there will either be a state or federal permit program. Subject to Congressional 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 CCR rule. For facilities located within the boundaries of Native American reservations, such as the Navajo Nation where Four Corners is located, EPA is required to develop a federal permit program regardless of appropriated funds. There is no timeline for establishing either state or federal permitting programs. Since the CCR rule was promulgated in 2015, it has undergone multiple revisions and may be subject to further change as a result of EPA’s ongoing review, implementation of the WIIN act, and the impact of various court decisions in litigation. On July 30, 2018, the EPA published a rule which constitutes “Phase One, Part One” of its ongoing reconsideration and revision of the April 17, 2015 coal ash rule. The final rule includes two types of revisions. The first revision extends the deadline to allow EGUs with unlined impoundments or that fail to meet the uppermost aquifer requirement to continue to receive coal ash until October 31, 2020. The second revision authorizes a “Participating State Director” or EPA, in lieu of a professional engineer, to approve suspension of groundwater monitoring and to issue certifications related to the location restrictions, design criteria, groundwater monitoring, remedy selection and implementation. The revisions also modify groundwater protection standards for certain constituents, which include cobalt, molybdenum, lithium, and lead without a maximum contamination level. EPA intends to issue multiple proposed rulemakings with a final rule in December 2019 that will include the following: (1) deadlines for unlined surface impoundments to cease receiving waste; (2) a “Phase Two” rule to address amendments to the national minimum criteria; and (3) rulemaking for alternative demonstration for unlined surface impoundments with a request for comment on inclusion of legacy units. On July 30, 2019, EPA released a proposed “Phase Two” rule and indicated they will provide a 60-day public comment period. PNM cannot predict the outcome of the EPA’s rule making activity or the outcome of any related litigation, and whether or how such a ruling would affect operations at Four Corners. The CCR 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 and the determination by EPA that CCRs are non-hazardous. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCR regulation, including mine placement of CCRs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. Based upon the requirements of the final rule, PNM conducted a CCR assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM would seek recovery from its ratepayers of all CCR costs for retail jurisdictional assets that are ultimately incurred. PNM does not expect the rule to have a material impact on operations, financial position, or cash flows. As indicated above, CCRs at Four Corners are currently disposed of in ash ponds and dry storage areas. The CCR rule requires ongoing, phased groundwater monitoring. Utilities that own or operate CCR disposal units, such as those at Four Corners were required to collect sufficient groundwater sampling data to initiate a detection monitoring program. Four Corners completed the analysis for its CCR disposal units, which identified several units that will need corrective action or will need to cease operations and initiate closure by October 2020. At this time, PNM does not anticipate its share of the cost to complete these corrective actions or to close the CCR disposal units at Four Corners will have a significant impact on its operations, financial position, or cash flows. Other Commitments and Contingencies Coal Supply SJGS The coal requirements for SJGS are supplied by SJCC. SJCC holds certain federal, state, and private coal leases. In addition to coal delivered to meet the current needs of SJGS, PNM has prepaid SJCC for certain coal mined but not yet delivered to the plant site. At June 30, 2019 and December 31, 2018, prepayments for coal, which are included in other current assets, amounted to $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 2018 Annual Reports on Form 10-K. In conjunction with the activities undertaken to comply with the CAA for SJGS, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS. On July 1, 2015, PNM and Westmoreland entered into a new coal supply agreement (the “SJGS CSA”), pursuant to which Westmoreland, through its indirect wholly-owned subsidiary SJCC, agreed to supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which CCR disposal and mine reclamation services for SJGS would be provided. As discussed in Note 6, with the closing of the sale of the assets of SJCC on March 15, 2019, WSJ LLC assumed the rights and obligations of SJCC under the SJGS CSA and the agreements for CCR disposal and mine reclamation services. Pricing under the SJGS CSA is primarily fixed, with adjustments to reflect changes in general inflation. The pricing structure takes into account that WSJ LLC has been paid for coal mined but not delivered. PNM had the option to extend the SJGS CSA, subject to negotiation of the term of the extension and compensation to the miner. In 2018, PNM, Los Alamos, UAMPS, and Tucson provided notice of their intent to exit SJGS in 2022 and Farmington gave notice that it wishes to continue SJGS operations and to extend the terms of both agreements. On November 30, 2018, PNM provided notice to Westmoreland that PNM does not intend to extend the term of the SJGS CSA or to negotiate a new coal supply agreement for SJGS, which will result in the current agreement expiring on its own terms on June 30, 2022. See additional discussion above of PNM’s December 2018 Compliance Filing above and its SJGS Abandonment Application in Note 12. In connection with certain mining permits relating to the operation of the San Juan mine, SJCC was 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. As discussed in Note 6, on March 15, 2019, the assets owned by SJCC were sold to WSJ LLC, a subsidiary of Westmoreland Mining Holdings, LLC. Under the sale agreement, WSJ LLC assumed the rights and obligations of SJCC, including obligations to PNMR under the outstanding letters of credit. 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 contract provides for pricing adjustments over its term based on economic indices. See additional discussion of the Four Corners CSA in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Coal Mine Reclamation As indicated under Coal Combustion Residuals Waste Disposal above, SJGS currently disposes of CCRs in the surface mine pits adjacent to the plant and Four Corners disposes of CCRs in ponds and dry storage areas. As discussed in Note 16 of the Notes to Consolidated Financial Statements in the 2018 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 periodically. The SJGS RA required PNM to complete an update to the reclamation cost estimate after the December 31, 2017 shutdown of SJGS Units 2 and 3. This reclamation cost estimate was completed in October 2018 and assumed continuation of mining operations through 2053. The 2018 study indicated a decrease in reclamation costs primarily driven by lower inflationary factors used to determine the estimated future cost of reclamation activities. PNM recorded its $2.5 million share of this decrease as of September 30, 2018 as regulatory disallowances and restructuring costs in the Condensed Consolidated Statements of Earnings. In December 2018 PNM remeasured its liability for coal mine reclamation for the mine that serves SJGS to reflect that reclamation activities may occur beginning in 2022, rather than in 2053 as previously anticipated. This estimate resulted in an increase in overall reclamation costs due to an increase in the amount of fill dirt required to remediate the mine areas and the timing of activities necessary to reclaim the mine that serves SJGS. This remeasurement increased PNM’s liability for coal mine reclamation as of December 31, 2018 by $39.2 million for both the underground and surface mines that serve SJGS. PNM recovers from retail customers reclamation costs associated with the underground mine. However, the NMPRC has capped the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million. As a result, PNM recorded $9.4 million of the increase in the liability at December 31, 2018 related to the underground mine in regulatory assets on the Condensed Consolidated Balance Sheets and recorded the remaining $29.8 million associated with the surface mine as regulatory disallowances and restructuring costs on the Condensed Consolidated Statements of Earnings. PNM’s estimate of the costs necessary to reclaim the mine that serves SJGS is subject to many assumptions, including the timing of reclamation, generally accepted practices at the time reclamation activities occur, and then current inflation and discount rates. In addition, PNM may be exposed to additional loss if recovery for the cost of reclamation activities is not approved by the NMPRC in connection with the NMPRC approvals indicated above. An updated coal mine reclamation study for the mine that serves Four Corners was completed in 2019. The updated study reflects operation of the mine through 2031, the term of the Four Corners CSA. The study indicates a decrease in anticipated coal mine reclamation costs primarily driven by lower overhead costs, which is offset by an increase driven by a reduction in the discount rate used to measure the liability. PNM recorded its share of the net decrease in the liability of $0.3 million as of June 30, 2019 and reflected the adjustment in cost of energy on the Condensed Consolidated Statements of Earnings. Based on the 2018 estimates and PNM’s ownership share of SJGS, PNM’s remaining payments as of June 30, 2019 for mine reclamation, in future dollars, are estimated to be $94.4 million for the surface mines at both SJGS and Four Corners and $40.0 million for the underground mine at SJGS. At June 30, 2019 and December 31, 2018, liabilities, in current dollars, of $70.0 million and $70.1 million for surface mine reclamation and $24.3 million and $23.2 million for underground mine reclamation were recorded in other deferred credits. Under the terms of the SJGS CSA, PNM and the other SJGS owners are obligated to compensate WSJ LLC 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 WSJ LLC for post-term reclamation obligations. As discussed in Note 16 of the Notes to the Consolidated Financial Statements on Form 10-K, as part of the restructuring of SJGS ownership 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 $10.0 million in December 2018. Based on PNM’s reclamation trust fund balance at June 30, 2019, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $6.1 million in 2019, $10.2 million in 2020, and $10.9 million in 2021. 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 in 2018 and anticipates providing additional funding of $2.3 million in each of the years from 2019 through 2023. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. The impacts of changes in New Mexico state law as a result of the enactment of the ETA and regulatory determinations made by the NMPRC may also affect PNM’s financial position, results of operations, and cash flows. See additional discussion above regarding PNM’s December 2018 Compliance Filing and its SJGS Abandonment Application in Note 12. 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 $13.9 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers. The remaining $13.5 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 $41.6 million, with a maximum annual payment limitation of $6.2 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 $2.8 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 2018 through 2021 has been endorsed by the parties and is being reviewed by the New Mexico Office of the State Engineer. In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for 40 years. PVNGS Water Supply Litigation In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Native American 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 NM 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. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM entered its appearance in the appellate case and supported the settlement agreement in the NM District Court. On April 3, 2018, the New Mexico Court of Appeals issued an order affirming the decision of the NM District Court. Several parties filed motions requesting a rehearing with the New Mexico Court of Appeals seeking clarification of the order, which were denied. The State of New Mexico and various other appellants filed a writ of certiorari with the NM Supreme Court. The NM Supreme Court granted the State of New Mexico’s petition and denied the other parties’ requests. The issues regarding the Navajo Nation settlement have been briefed and are awaiting a decision by the NM Supreme Court. 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. After extensive challenges to the validity of the ordinance, the utilities filed a writ of certiorari with the NM Supreme Court, which was denied. The matter is proceeding in NM District Court. The utilities and Bernalillo County have reached a standstill agreement whereby the county will 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. Discussions are continuing but the matter remains unresolved. 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 In September 2012, 43 landowners filed a notice of appeal with the Bureau of Indian Affairs (“BIA”) appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The landowners claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that PNM is a rights-of-way grantee 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. The allottees 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. The allottees filed a motion to dismiss their appeal with prejudice, which was granted in April 2014. 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 September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. 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. Both matters have been consolidated. Oral argument before the Tenth Circuit was heard on January 17, 2017. On May 26, 2017, the Tenth Circuit affirmed the district court. On July 8, 2017, PNM filed a Motion for Reconsideration en banc with the Tenth Circuit, which was denied. The NM District Court stayed the case 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, which was denied. The underlying litigation continues in the NM District Court. On March 27, 2019, several individual allottees filed a motion for partial summary judgment on the issue of trespass. The Court held a hearing on the motion on June 18, 2019 and took the motion under advisement. PNM cannot predict the outcome of these matters.
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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 2018 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 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 other 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 and included a request for a revenue decoupling pilot program for residential and small commercial customers. 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). After additional hearings, 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 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. In August 2016, the Hearing Examiner in the case issued a recommended decision (the “August 2016 RD”). The August 2016 RD, among other things, 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. As a result, the August 2016 RD recommended the NMPRC disallow recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases aggregating 64.1 MW of PVNGS Unit 2, the undepreciated capital improvements made during the period the 64.1 MW of purchased capacity was leased, rent expense aggregating $18.1 million annually for leases aggregating 114.6 MW of capacity that were extended through January 2023 and 2024 (Note 13), and recovery of the costs of converting SJGS Units 1 and 4 to BDT. 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. Specifically, PNM appealed the NMPRC’s determination the PNM was imprudent in certain matters in the case, including the NMPRC’s disallowance of the full purchase price of the 64.1 MW of capacity in PVNGS Unit 2, the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM, the cost of converting SJGS Units 1 and 4 to BDT, and 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. NEE, NMIEC, and ABCWUA filed notices of cross-appeal to PNM’s appeal. The issues appealed by the various cross-appellants included, among other things, the NMPRC allowing PNM to recover any of the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and the purchase price for the 64.1 MW in PVNGS Unit 2, the costs incurred under the Four Corners CSA, and the inclusion of the “prepaid pension asset” in rate base. During the pendency of the appeal, PNM evaluated the consequences of the order in the NM 2015 Rate Case and the related appeals to the NM Supreme Court as required under GAAP. These evaluations indicated that it was reasonably possible that PNM would be successful on the issues it was appealing but would not be provided capital costs recovery until the NMPRC acted on a decision of the NM Supreme Court. PNM also evaluated the accounting consequences of the issues being appealed by the cross-appellants and concluded that the issues raised in the cross-appeals did not have substantial merit. In accordance with GAAP, PNM periodically updated its estimate of the amount of time necessary for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. As a result of these evaluations, through March 31, 2019, PNM recorded accumulated pre-tax impairments of its capital investments subject to the appeal in the amount of $19.7 million, which includes pre-tax losses of $1.3 million recorded during the three months ended March 31, 2019 and $1.8 million recorded during the six months ended June 30, 2018. On May 16, 2019, the NM Supreme Court issued its decision on the matters that had been appealed in the NM 2015 Rate Case. The NM Supreme Court rejected the matters appealed by the cross-appellants and affirmed the NMPRC’s disallowance of a portion of the purchase price of the 64.1 MW of capacity in PVNGS Unit 2; the undepreciated costs of capital improvements made during the time that the 64.1 MW capacity was leased by PNM; and the costs to install BDT at SJGS Units 1 and 4. The NM Supreme Court’s decision also ruled that the NMPRC’s decision to permanently disallow recovery of future decommissioning costs related to the 64.1 MW of PVNGS Unit 2 and the 114.6 MW of PVNGS Units 1 and 2 deprived PNM of its rights to due process of law and remanded the case to the NMPRC for further proceedings consistent with the Court’s findings. On July 17, 2019, the NMPRC heard oral argument from parties in the case on how to best proceed with the NM Supreme Court’s remand. At oral argument, parties presented various positions ranging from re-litigating the value of PVNGS resources determined by the NMPRC and affirmed by the NM Supreme Court to re-affirming the NMPRC’s final order with a single modification to address recovery of future PVNGS decommissioning costs in a future case. PNM is unable to predict the outcome of this matter. As a result of the NM Supreme Court’s ruling, PNM recorded a pre-tax impairment of $149.3 million as of June 30, 2019 which is reflected as regulatory disallowances and restructuring costs in the Condensed Consolidated Statements of Earnings. The impairment reflects capital costs not previously impaired during the pendency of the appeal and includes $72.6 million for a portion of the purchase price for 64.1 MW in PVNGS Unit 2, $39.3 million of undepreciated capitalized improvements made during the period the 64.1 MW was being leased by PNM, and $37.4 million for BDT on SJGS Units 1 and 4. The impairment was offset by tax impacts of $45.7 million, which are reflected as income taxes on the Condensed Consolidated Statements of Earnings. 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 were at issue in its then pending appeal to the NM Supreme Court. PNM’s original application used a FTY beginning January 1, 2018 and requested an increase in base non-fuel revenues of $99.2 million based on an ROE of 10.125%. The primary drivers of PNM’s revenue deficiency included implementation of modifications to PNM’s resource portfolio, which were approved by the NMPRC in December 2015 as part of the SJGS regional haze compliance plan, infrastructure investments, including environmental upgrades at Four Corners, declines in forecasted energy sales due to successful energy efficiency programs and other economic factors, and updates to FERC/retail jurisdictional allocations. After extensive settlement negotiations and public proceedings, the NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The key terms of the Revised Order include:
In accordance with the settlement agreement and the NMPRC’s final order, PNM implemented 50% of the approved increase for service rendered beginning February 1, 2018 and implemented the rest of the increase for service rendered beginning January 1, 2019. 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 several questions related to establishing and monitoring utilities’ ROEs, the recoverability of regulatory assets, including rate case costs, and whether parties should have access to software used by utilities to support their positions. To date, no agreement has been reached. PNM cannot predict the outcome of this proceeding. Renewable Portfolio Standard Prior to the enactment of the ETA, the REA established 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. As discussed in Note 11, the ETA was enacted on June 14, 2019. The ETA amends the REA and requires utilities operating in New Mexico to have renewable portfolios equal to 20% by 2020, 40% by 2025, 50% by 2030, 80% by 2040, and 100% zero-carbon energy by 2045. The ETA also removes diversity requirements and certain customer caps and exemptions relating to the application of the RPS under the REA. 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. The ETA sets a RCT of $60 per MWh using an average annual levelized resource cost basis. 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:
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. 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. PNM 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 and requested a partial stay of the NMPRC order, which was denied. NEE subsequently filed a motion to intervene and cross-appeal objecting to the approval of the 50 MW of new solar facilities. On July 5, 2019, the NM Supreme Court approved a motion filed by NMIEC to dismiss its appeal. NEE’s cross-appeal remains open. PNM cannot predict the outcome of this matter. On June 1, 2018, PNM filed its 2019 renewable energy procurement plan. The plan met RPS and diversity requirements for 2019 and 2020 using resources already approved by the NMPRC and did not propose any significant new procurements. PNM projects that the plan will be within the RCT in 2019 and will slightly exceed the current RCT in 2020. The NMPRC approved PNM’s 2019 renewable energy procurement plan on November 28, 2018. On June 3, 2019, PNM filed its 2020 renewable energy procurement plan. The plan requests approval of a 20-year PPA to purchase 140 MW of renewable energy and RECs from the La Joya Wind Facility (“La Joya Wind”), which is expected to be operational by December 31, 2020. PNM intends to utilize the BB2 line to deliver power from the PPA. See additional discussion below under Application For a New 345 kV Transmission Line. As discussed above, the ETA removes certain customer caps and exemptions relating to the application of the RPS under the REA. PNM’s 2020 renewable energy procurement plan requests a variance from the RPS for 2020 and proposes the shortfall be met with excess RECs that will be available under the La Joya Wind PPA in 2021. PNM also submitted proposed adjustments to the current FPPAC methodology for non-renewable fuel allocations to reflect the ETA’s removal of certain customer cost caps associated with the RPS and requested that the fuel clause year be reset to correspond to the January 1 reset date under the renewable energy rider. On July 17, 2019, PNM filed a corrected reconciliation of 2019 and estimated 2020 customer bill impacts that demonstrated the effect of removing certain customer caps and exemptions under the requirements of the newly enacted ETA. The Hearing Examiner issued a response requiring PNM to address why its application should not be dismissed, or alternatively, proposing an extended procedural schedule. PNM’s response proposed the application not be dismissed, that a corrected public notice be issued, and that the procedural schedule be extended by 60 days. On July 30 2019, the Hearing Examiner issued a revised procedural order that extended the review period through January 29, 2019 and set hearings to begin on October 24, 2019. 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 its 2019 renewable energy procurement plan case, which was approved by the NMPRC on November 28, 2018, PNM proposed to collect $49.6 million for the year. The 2019 renewable energy procurement plan became effective on January 1, 2019. PNM recorded revenues from the rider of $12.8 million and $25.5 million in the three and six months ended June 30, 2019 and $10.8 million and $21.7 million in the three and six months ended June 30, 2018. In its 2020 renewable energy procurement plan, PNM proposes to collect $58.9 million for 2020. 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 did not exceed such limitation in 2018. Energy Efficiency and Load Management Petition for Energy Efficiency Disincentive PNM’s 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. During the 2019 New Mexico legislative session, the Efficient Use of Energy Act was amended to, among other things, include a decoupling mechanism for disincentives, preclude a reduction to a utility’s ROE based on approval of disincentive or incentive mechanisms, and to establish savings targets for the period 2021 through 2025. On May 6, 2019, PNM submitted a request to the NMPRC to dismiss this matter. PNM will propose a mechanism to address disincentives in a future general rate case filing. The NMPRC approved PNM’s request to dismiss the matter on June 12, 2019, concluding this matter. 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. 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 and because they asserted that the 2014 IRP did not conform to the NMPRC’s IRP rule. 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. On May 4, 2016, the NMPRC issued a 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 the 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. 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 included, among other things, that retiring PNM’s share of SJGS in 2022 and existing ownership in Four Corners in 2031 would provide long-term cost savings for PNM’s customers and that the best mix of new resources to replace the retired coal generation would include solar energy and flexible natural gas-fired peaking capacity as well as energy storage, if the economics support it, and wind energy provided additional transmission capacity becomes available. The 2017 IRP also indicated that PNM should retain the currently leased capacity in PVNGS. 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. On December 19, 2018, after public hearings and consideration of the Hearing Examiner’s recommendations, the NMPRC issued a final order accepting PNM’s 2017 IRP as compliant with applicable statute and NMPRC rules. On January 18, 2019, the Board of the County of Commissioners for San Juan County, New Mexico, the City of Farmington, New Mexico, and other parties filed a Notice of Appeal with the NM Supreme Court regarding the NMPRC’s final order in PNM’s 2017 IRP. On January 18, 2019, NEE submitted a motion requesting the NMPRC reconsider its acceptance of PNM’s 2017 IRP and alleging informational inadequacy and deficiencies in PNM’s filing, which was deemed denied. On February 19, 2019, NEE filed a motion with the NM Supreme Court to intervene in the appeal and to seek remand of the matter to the NMPRC. On March 11, 2019, PNM filed its response with the NM Supreme Court stating that the NMPRC has already considered and, by operation of law, denied NEE’s motion for reconsideration. On May 10, 2019, the appellants, excluding NEE, filed a motion with the NM Supreme Court to dismiss their appeal, which was supported by PNM. On May 31, 2019, the NM Supreme Court denied NEE’s request to remand the proceeding to the NMPRC and ordered NEE to respond to the motion to dismiss the appeal. On June 4, 2019, NEE responded that it did not oppose the appellants’ request to dismiss their appeal. On July 26, 2019, the NM Supreme Court granted the parties’ motions to dismiss the appeal. This matter is now concluded. As discussed below, on July 1, 2019, PNM submitted its SJGS Abandonment Application with the NMPRC requesting approval to retire SJGS in 2022, for replacement resources, and for the issuance of securitized financing under the ETA. Many of the assumptions and findings included in PNM’s July 1, 2019 filing were consistent with those identified in PNM’s 2017 IRP. The SJGS Abandonment Application and the 2017 IRP are not a final determinations of PNM’s future generation portfolio. PNM will also be required to obtain NMPRC approval of an exit from Four Corners, which PNM will seek at an appropriate time in the future. Likewise, NMPRC approval of new generation resources through CCNs, PPAs, or other applicable filings will be required. PNM cannot predict the outcome of these matters. SJGS Abandonment Application On July 1, 2019, PNM filed a Consolidated Application for the Abandonment and Replacement of SJGS and Related Securitized Financing Pursuant to the ETA (the “SJGS Abandonment Application”). The SJGS Abandonment Application seeks NMPRC approval to retire PNM’s share of SJGS after the existing coal supply and participation agreements end in June 2022, for approval of replacement resources, and for the issuance of “energy transition bonds,” as provided by the ETA. PNM’s application proposes several replacement resource scenarios including PNM’s recommended replacement scenario, which would provide cost savings to customers compared to continued operation of SJGS, preserves system reliability, and is consistent with PNM’s plan to have an emissions-free generation portfolio by 2040. This plan would provide PNM authority to construct and own a 280 MW natural gas-fired peaking plant, to be located on the existing SJGS facility site and 70 MW of battery storage facilities. In addition, PNM’s recommended replacement resource scenario would allow PNM to execute PPAs to procure renewable energy from a total of 350 MW of solar-PV generating facilities and for energy from a total of 60 MW of battery storage facilities. PNM’s application included three other replacement resource scenarios that would place a greater amount of resources in the San Juan area, or result in no new fossil-fueled generating facilities or battery storage facilities. Each of these alternative replacement resource scenarios is expected to result in increased costs to customers and lower expected system reliability when compared to PNM’s recommended replacement resource scenario. The SJGS Abandonment Application includes a request to issue approximately $361 million of energy transition bonds (the “Securitized Bonds”). The amount of Securitized Bonds to be issued will be dependent upon several factors, including NMPRC approval of the SJGS Abandonment Application. Funding under the Securitized bonds is currently expected to include approximately $283 million of forecasted undepreciated investments in SJGS at June 30, 2020, an estimated $28.6 million for plant decommissioning and coal mine reclamation costs, approximately $9.6 million in upfront financing costs, and approximately $20.0 million for job training and severance costs for affected employees. Proceeds from the Securitization Bonds would also be used fund approximately $19.8 million for economic development in the four corners area. As discussed in Note 11, the NM Supreme Court granted a request by PNM to stay a January 30, 2019 NMPRC order requiring PNM’s SJGS abandonment application be filed by March 1, 2019. On June 26, 2019, the NM Supreme Court lifted the stay and denied PNM’s petition without discussion. On July 10, 2019, the NMPRC issued an order requiring the SJGS Abandonment Application be considered in two proceedings, one addressing SJGS abandonment and related financing and the other addressing replacement resources. The NMPRC indicated that PNM’s July 1, 2019 filing is responsive to the January 30, 2019 order but did not indicate if the abandonment and financing proceedings will be evaluated under the requirements of the ETA. The NMPRC’s July 10, 2019 order also extended the deadline to issue the abandonment and financing order to nine months and to issue the replacement resources order to 15 months. On July 22, 2019, Western Resource Advocates filed a motion for clarification, reconsideration, and request for oral argument with the NMPRC. The motion requested the NMPRC clarify whether it intends to evaluate the abandonment and financing proceeding under the requirements of the ETA and, in the event the NMPRC does not intend to apply the ETA to the abandonment and financing proceeding, to reconsider its decision and provide parties an opportunity to present oral argument on the matter. The NMPRC chair responded on July 24, 2019, indicating that the Hearing Examiners assigned to the proceeding would address the issue of law applicable to the approvals sought by PNM in the scheduling orders. On July 25, 2019, the Hearing Examiners issued procedural orders that set a public hearing on SJGS abandonment and related financing for December 10, 2019, a hearing on PNM’s proposed PPA replacement resources on December 2, 2019, and a hearing on the remaining replacement resources on March 2, 2020. The procedural orders also require PNM to file legal brief by August 23, 2019 regarding the extent to which the state constitution might prevent the ETA from applying to the issues in each proceeding, that parties file responses to PNM’s legal briefs by October 18, 2019, and that parties may file testimony on the merits of their claims regarding the SJGS abandonment and replacement resources if the ETA is ultimately determined to not apply to PNM’s application. On July 29, 2019, Western Resource Advocates filed a motion for interlocutory appeal of the July 24, 2019 order indicating that the procedural order will not provide parties adequate time to determine the applicability of the ETA and requesting an expedited decision from the NMPRC stating their intent to review the proceedings under the requirements of the ETA or under prior law. On August 1, 2019, the NMPRC issued a procedural order requiring responses to the interlocutory appeal by August 9, 2019. The financial impact of an early retirement of SJGS and the NMPRC approval process are influenced by many factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment on the area surrounding the plant and the related mine, as well as the overall political and economic conditions of New Mexico. PNM believes that the ETA applies to all aspects of the SJGS Abandonment Application but cannot predict the outcome of this matter. Joint Petition to Investigate PNM’s Option to Purchase Assets Underlying Certain Leases in PVNGS On April 22, 2019, NEE and other parties, which consist primarily of environmental not-for-profit organizations, filed a joint petition for expedited investigation with the NMPRC. The joint petition requested the NMPRC open an investigation regarding PNM’s option to purchase the assets underlying the PVNGS Unit 1 and 2 leases that will expire in January 2023 and 2024. Various parties filed to participate in the request. On May 8, 2019, the NMPRC issued an order requiring a response from both PNM and NMPRC staff. PNM filed responses indicating, among other things, that the joint petition should be denied and that PNM has not yet made a decision to purchase or return the assets underlying the leases that expire in January 2023 and 2024. The NMPRC has not taken action on the joint petition for investigation. PNM cannot predict the outcome of this matter. Cost Recovery Related to Joining the EIM The California Independent System Operator (“CAISO”) developed the Western Energy Imbalance Market (“EIM”) as a real-time wholesale energy trading market that enables participating electric utilities to buy and sell energy. The EIM aggregates the variability of electricity generation and load for multiple balancing authority areas and utility jurisdictions. In addition, the EIM facilitates greater integration of renewable resources through the aggregation of flexible resources by capturing diversity benefits from the expanded geographic footprint and the expanded potential uses for those resources. In 2018, PNM completed a cost-benefit analysis of participating in the EIM. PNM’s analysis indicated participation in the EIM would provide substantial benefits to retail customers. On August 22, 2018, PNM filed an application with the NMPRC requesting, among other things, to recover an estimated $20.9 million of initial capital investments and authorization to establish a regulatory asset to recover an estimated $7.4 million of other expenses that would be incurred in order to join the EIM. PNM’s application proposed the regulatory asset be adjusted to provide for full recovery of such costs, including carrying charges, until the effective date of new rates in PNM’s next general rate case. PNM’s application also proposed the benefits of participating in the EIM be credited to retail customers through PNM’s existing FPPAC and that PNM would seek recovery of its costs in a future proceeding. On December 19, 2018, the NMPRC issued an order approving the establishment of a regulatory asset to recover PNM’s cost of joining the EIM, which was subsequently challenged by several parties. On February 6, 2019, the NMPRC issued an order granting rehearing and vacating the December 19, 2018 order. On March 18, 2019, the Hearing Examiner issued an updated recommended decision recommending approval of the establishment of a regulatory asset but deferring certain rate making issues, including but not limited to issues related to implementation and ongoing EIM costs and savings, the prudence and reasonableness of costs to be included in the regulatory asset, and the period over which costs would be charged to customers until PNM’s next general rate case filing, which was approved by the NMPRC. PNM and other parties filed a joint motion requesting the NMPRC clarify that the quarterly benefits reports prepared by CAISO be used to determine the benefits of participating in the EIM, as well as to support the prudence of costs incurred to join the EIM. On April 24, 2019, the NMPRC issued an order granting the joint motion for clarification and indicating the CAISO quarterly benefits reports may be used in a future rate case. PNM anticipates it will begin participating in the EIM in April 2021. Facebook, Inc. Data Center Project As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K, in 2016, the NMPRC approved a PNM application for arrangements in connection with services to be provided to Facebook, Inc. for a data center being constructed in PNM’s service area. 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. The cost of renewable energy procured is passed through to Facebook under a rate rider. A 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. In late 2017, PNM’s executed its initial procurement for the energy production from 30 MW of solar-PV capacity from NMRD, a 50% equity method of investee PNMR Development. Of this capacity, 10 MW began commercial operation in each of January 2018, March 2018, and May 2018. PNM obtained NMPRC approval to enter into additional 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply renewable energy to the data center. These PPAs include the purchase of the power and RECs from:
The two PPAs aggregating approximately 100 MW of capacity were subject to FERC approval, which was granted on August 1, 2019. Application For a New 345 kV Transmission Line On August 10, 2018, PNM filed an application seeking NMPRC approval of a CCN to construct and operate a 345 kV transmission line and associated facilities (the “BB2 Line”), and to determine the rate making treatment to apply to the BB2 line and related rights-of-way. In the application, PNM states that the BB2 line would run adjacent to one of PNM’s existing transmission lines and is necessary to serve additional renewable generating resources to be located in eastern New Mexico. PNM’s use of the BB2 line would benefit all customers and would include delivery of approximately 166 MW of renewable energy and RECs under a PPA, which had previously been approved by the NMPRC, from La Joya Wind and 140 MW from La Joya Wind that PNM included in PNM’s 2020 renewable energy procurement plan. PNM’s application requested that the NMPRC apply standard ratemaking treatment to the estimated $85 million cost of the project resulting in a jurisdictional allocation of costs to all of PNM’s transmission and retail customers. NMPRC staff supported PNM’s proposed ratemaking treatment of the BB2 project and indicated that the capacity and energy of the La Joya Wind PPA and related network upgrades to PNM’s transmission system would benefit all of PNM’s customers. On March 11, 2019, the Hearing Examiner assigned to the application issued a recommended decision recommending approval of the CCN and related rights-of-way but recommending the NMPRC deny PNM’s request to allocate a portion of cost of the BB2 Line to retail customers. The Hearing Examiner’s recommendation indicated the costs not recovered from retail customers be directly reimbursed to PNM by Facebook, Inc. As a result, Facebook, Inc. would be responsible for approximately 46 percent, or $39.0 million, of the estimated cost of the project. On March 20, 2019, PNM filed exceptions to the recommended decision and requested oral argument. In its filing, PNM refuted the proposed finding that the BB2 Line is not part of PNM’s overall transmission system, opposed the recommendation that approximately 46 percent of the estimated cost of the project be directly assigned to Facebook, Inc. and presented legal arguments in support of PNM’s originally proposed ratemaking treatment. On April 16, 2019, the NMPRC issued an order approving the Hearing Examiner’s recommended decision, including the requirement that PNM be directly reimbursed by Facebook, Inc. In late April 2019, PNM and other parties submitted filings with the NMPRC requesting rehearing and seeking reconsideration of the NMPRC’s decision to deny standard ratemaking treatment of the cost of the BB2 Line and associated facilities, which were denied. On May 21, 2019, PNM filed a motion requesting the NMPRC reopen the proceeding to admit new evidence of the benefits of the BB2 Line to retail customers and to modify the final order. On June 12, 2019, the NMPRC issued an updated final order but denied PNM’s motion to reopen the proceedings. The updated final order grants the CCN but defers rate making treatment to a future rate case. This matter is now concluded. Western Spirit Line On May 1, 2019, PNM, the New Mexico Renewable Energy Transmission Authority (“RETA”), a New Mexico state authority, and Western Spirit Transmission LLC (“Western Spirit”), an affiliate of Pattern Energy Group, Inc., entered into agreements for the construction of a transmission line to transmit power generated from wind facilities to be owned by Pattern Wind New Mexico, LLC (“Pattern Wind”), an affiliate of Western Spirit and Pattern Development. As a part of the arrangement, the parties executed a Build Transfer Agreement (“BTA”) that would allow PNM to purchase the approximately 165-mile 345 kV transmission line and associated facilities (the “Western Spirit Line”). Subject to NMPRC and FERC approval, the Western Spirit Line will be developed and constructed by RETA and Western Spirit LLC and sold to PNM upon its commercial operation date. The BTA contains a number of customary representations and warranties and indemnification provisions as well as closing conditions, including regulatory and third-party approvals, and may be terminated under certain circumstances. The purchase is subject to, among other conditions, receiving approval from FERC, the NMPRC, and, if necessary, anti-trust review under the Hart-Scott-Rodino Act. PNM estimates the total cost of the project to be approximately $285 million, including an estimated $75 million that Pattern Wind has chosen to self-fund under the agreement. On May 10, 2019, PNM filed an application with the NMPRC requesting that the NMPRC determine that it is not unlawful or inconsistent with the public interest for PNM to purchase the Western Spirit Line and requesting the NMPRC rule by November 6, 2019. On July 23, 2019, NMPRC staff filed testimony contending that a CCN is required for PNM to own and operate the Western Spirit Line. A hearing is scheduled to begin on August 13, 2019. PNM also has entered into Transmission Service Agreements and other ancillary agreements (“TSAs”) with Pattern Wind for firm transmission service. The TSAs use an incremental rate based on the construction and other ongoing costs of the Western Spirit Line, including adjustments for construction costs that Pattern Wind has chosen to self-fund under the agreement. FERC approved PNM’s TSAs with Pattern Wind effective July 9, 2019. PNM anticipates FERC will issue an order regarding PNM’s purchase of the Western Spirit Line in November 2019. TNMP TNMP 2018 Rate Case On May 30, 2018, TNMP filed a general rate proceeding with the PUCT (the “TNMP 2018 Rate Case”) requesting an annual increase to base rates of $25.9 million based on a ROE of 10.5%, a cost of debt of 7.2%, and a capital structure comprised of 50% debt and 50% equity. TNMP’s application included a request to establish new rate riders to recover Hurricane Harvey restoration, rate case, and additional vegetation management costs. The application also included the integration of revenues previously recorded under the AMS rider and collection of other unrecovered AMS investments into base rates. In 2018, TNMP recorded revenues of $20.2 million under the AMS rider. The TNMP 2018 Rate Case application also proposed to return the regulatory liability recorded at December 31, 2017 related to federal tax reform to customers and to reduce the federal corporate income tax rate to 21%. On December 20, 2018, the PUCT approved an unopposed settlement agreement in the case. The PUCT’s final order results in a $10.0 million annual increase to base rates. The key elements of the approved settlement include a ROE of 9.65%, a cost of debt of 6.44%, and a capital structure comprised of 55% debt and 45% equity. As stated by the settlement agreement, the PUCT’s final order excludes certain items from rate base that were requested in TNMP’s original filing, including approximately $10.6 million of transmission investments that TNMP included in its January 2019 transmission cost of service filing, which was approved by the PUCT in March 2019. In addition, the PUCT’s final order requires TNMP to refund approximately $37.8 million of the regulatory liability recorded at December 31, 2017 related to federal tax reform to customers over a period of five years and the remaining amount over the estimated useful lives of plant in service as of December 31, 2017; approves TNMP’s request to integrate revenues historically recorded under TNMP’s AMS rider, as well as other unrecovered AMS investments, into base rates; approves TNMP’s request for new depreciation rates; and approves a new rider to recover Hurricane Harvey restoration costs, net of amounts to be refunded to customers resulting from the reduction in the federal income tax rate in 2018. See Note 14. The TNMP 2018 Rate Case also resulted in a reallocation of costs between TNMP’s transmission and retail customers and other rate design changes that reallocate costs between certain demand-based customers and customers billed on a volumetric basis. New rates under the TNMP 2018 Rate Case were effective beginning January 1, 2019. Transmission Cost of Service Rates TNMP can update its transmission cost of service (“TCOS”) rates twice per year to reflect changes in its invested capital although updates are not allowed while a general rate case is in process. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s recent interim transmission cost rate increases:
On July 23, 2019, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $21.9 million, which would increase revenues by $3.3 million annually. The application is pending before the PUCT. Order Related to Changes in Federal Income Tax Rates On January 25, 2018, the PUCT issued an accounting order that addresses the change in the federal corporate income tax rates on investor-owned utilities in the state of Texas. The order required investor-owned utilities to record a regulatory liability equal to the reduction in accumulated federal deferred income tax balances at the end of 2017 due to the change in the federal corporate income tax rate. In addition, the order required 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. In compliance with the PUCT order, during the three and six months ended June 30, 2018, TNMP reduced revenues by $1.2 million and $2.7 million to reflect the impact of the reduction in the federal corporate income tax rate beginning January 25, 2018. As discussed above, the total amount owed for the year ended 2018 of $5.4 million was offset against TNMP’s Hurricane Harvey restoration costs and is being refunded to customers as a component of a new rate rider over a period of approximately three years beginning on January 1, 2019. Energy Efficiency TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under and over collected costs from prior years, rate case expenses, and performance bonuses (if programs exceed mandated savings goals). On May 30, 2019, TNMP filed its request to adjust the EECRF to reflect changes in costs for 2020. The total amount requested was $5.9 million, which included a performance bonus of $0.8 million based on TNMP’s energy efficiency achievements in the 2018 plan year. Hearings for this matter have been scheduled for August 16, 2019. TNMP’s 2018 EECRF filing requested an adjustment of $5.6 million, including a performance bonus of $0.8 million, and became effective on March 1, 2019.
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Lease Commitments | Lease Commitments The Company enters into various lease agreements to meet its business needs and to satisfy the needs of its customers. Historically, the Company’s leases were classified as operating leases which included leases for generating capacity from PVNGS Units 1 and 2, certain rights-of-way agreements for transmission lines and facilities, vehicle and equipment leases necessary to construct and maintain the Company’s assets and building and office equipment leases. In February 2016, the FASB issued ASU 2016-02 – Leases (Topic 842) to provide guidance on the recognition, measurement, presentation, and disclosure of leases. Among other things, ASU 2016-02 requires that all leases be recorded on the balance sheets by recognizing a present value liability for future cash flows of the lease agreement and a corresponding right-of-use asset. The Company adopted Topic 842 on January 1, 2019, its required effective date. The Company elected to use many of the practical expedients available upon adoption of the standard. As a result, the Company will continue to classify its leases existing as of December 31, 2018 as operating leases until they expire or are modified. In addition, the Company elected the practical expedient to not reevaluate the accounting for land easements and rights-of-way agreements existing at December 31, 2018. The Company also elected the use of the practical expedient to apply the requirements of the new standard on its effective date and has not restated prior periods to conform to the new guidance. Adoption of the lease standard has a material impact on the Company’s Condensed Consolidated Balance Sheets but does not have a material impact on the Condensed Consolidated Statements of Earnings or the Condensed Consolidated Statements of Cash Flows. Effective January 1, 2019, the Company accounts for contracts that convey the use and control of identified assets for a period of time as leases. The Company classifies leases as operating or financing by evaluating the terms of the lease agreement. Agreements under which the Company is likely to utilize substantially all of the economic value or life of the asset or which the Company is likely to own at the end of the lease term, either through purchase or transfer of ownership, are classified as financing leases. Leases not meeting these criteria are accounted for as operating leases. Agreements under which the Company is a lessor are insignificant. Leases with terms that are expected to exceed one year are recognized on the Company’s Condensed Consolidated Balance Sheets by recording a lease liability and corresponding right-of-use asset. PNMR, PNM, and TNMP determine present value for their leases using their incremental borrowing rates at the commencement date of the lease or, when readily available, the rate implicit in the agreement. However, in most cases the implicit interest rate is not available in the Company’s lease agreements. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings. PVNGS PNM leases interests in Units 1 and 2 of PVNGS. The PVNGS leases were entered into in 1985 and 1986 and initially were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases and one lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. The four Unit 1 leases now expire on January 15, 2023 and the one Unit 2 lease now expires on January 15, 2024. The annual lease payments during the renewal periods aggregate $16.5 million for PVNGS Unit 1 and $1.6 million for Unit 2. The terms of each of the extended leases do not provide for additional renewal options beyond their currently scheduled expiration dates. PNM has the option to purchase the assets underlying each of the extended leases at their fair market value or to return the lease interests to the lessors on the expiration dates. Under the terms of the extended leases, PNM has until January 15, 2020 for the Unit 1 leases and January 15, 2021 for the Unit 2 lease to provide notices to the lessors of PNM’s intent to exercise the purchase options or to return the leased assets to the lessors. PNM’s elections are independent for each lease and are irrevocable. In the proceeding addressing PNM’s 2017 IRP (Note 12), PNM agreed to promptly notify the NMPRC of a decision to extend the Unit 1 or 2 leases, or to exercise its option to purchase the leased assets at fair market value upon the expiration of leases. If PNM elects to exercise its purchase option under any of the leases, the leases provide an appraisal process to determine fair market value. If PNM elects to return the assets underlying the extended leases, PNM will retain certain obligations related to PNVGS, including costs to decommission the facility. PNM would seek to recover its undepreciated investments at the end of the PVNGS leases as well as any future obligations related to PNM’s leased capacity from NM retail customers. Any transfer of the assets underlying the leases will be required to comply with NRC licensing requirements. See Note 12 for information concerning the NMPRC’s treatment of PNM’s purchase of assets underlying 64.1 MW and extension of 114.6 MW of leased capacity in PVNGS Unit 2, the NM Supreme Court’s decision regarding PNM’s appeal of certain matters in the NM 2015 Rate Case, as well as information concerning a joint petition to investigate PNM’s option to purchase additional assets underlying the extended leased capacity in PVNGS. Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the lessors and take title to the leased interests. If such an event had occurred as of June 30, 2019, amounts due to the lessors under the circumstances described above would be up to $161.2 million, payable on July 15, 2019 in addition to the scheduled lease payments due on July 15, 2019. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid. Land Easements and Rights-of-Ways Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million, subject to adjustment each year based on the Consumer Price Index, through 2029. PNM’s April 2018 payment for the amount due under the Navajo Nation right-of-way lease was $6.9 million, which included amounts due under the Consumer Price Index adjustment, and was used to determine PNM’s operating lease liability as of January 1, 2019 and is included in the table of future lease payments shown below. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments. Fleet Vehicles and Equipment As of December 31, 2018, all of the Company’s leases of fleet vehicles and equipment are classified as operating leases. Historically, the Company has utilized substantially all of the economic value of its fleet and equipment leases by the end of the lease term. The Company generally has the contractual ability to return its fleet vehicle and equipment leases to the lessor after one year provided the lessor can recover remaining amounts owed under the agreement from third-parties or through make-whole provisions in the contract but does not typically exercise this right. As a result, fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. The Company has elected to combine these fees with the lease components of the agreement. Certain of the Company’s fleet vehicle and equipment leases contain residual value guarantees. At June 30, 2019, residual value guarantees on fleet vehicle and equipment leases are $0.5 million, $1.1 million, and $1.6 million for PNM, TNMP, and PNMR. Other The Company holds a number of office space and office equipment leases. The Company’s current office space leases, all of which existed as of December 31, 2018, are classified as operating leases. These agreements include non-lease components for costs such as common area maintenance fees, which the Company has elected to combine with the lease component of the agreements. Certain of the Company’s office space leases are held between the Company’s consolidated subsidiaries and have been eliminated on consolidation. See Note 15. The Company’s office equipment leases are primarily for copiers and other graphics equipment. The Company classifies its office equipment leases existing as of December 31, 2018 as operating leases. Office equipment leases commencing on or after January 1, 2019 are classified as financing leases. Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below:
As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases. Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:
Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:
Information for the components of lease expense is as follows:
Supplemental cash flow information related to the Company’s leases is as follows:
Excluded from the operating and financing cash paid for leases above are $0.7 million and $0.1 million at PNM, $1.3 million and $0.1 million at TNMP, and $2.0 million and $0.2 million at PNMR. These capitalized costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2019. Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below:
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Lease Commitments | Lease Commitments The Company enters into various lease agreements to meet its business needs and to satisfy the needs of its customers. Historically, the Company’s leases were classified as operating leases which included leases for generating capacity from PVNGS Units 1 and 2, certain rights-of-way agreements for transmission lines and facilities, vehicle and equipment leases necessary to construct and maintain the Company’s assets and building and office equipment leases. In February 2016, the FASB issued ASU 2016-02 – Leases (Topic 842) to provide guidance on the recognition, measurement, presentation, and disclosure of leases. Among other things, ASU 2016-02 requires that all leases be recorded on the balance sheets by recognizing a present value liability for future cash flows of the lease agreement and a corresponding right-of-use asset. The Company adopted Topic 842 on January 1, 2019, its required effective date. The Company elected to use many of the practical expedients available upon adoption of the standard. As a result, the Company will continue to classify its leases existing as of December 31, 2018 as operating leases until they expire or are modified. In addition, the Company elected the practical expedient to not reevaluate the accounting for land easements and rights-of-way agreements existing at December 31, 2018. The Company also elected the use of the practical expedient to apply the requirements of the new standard on its effective date and has not restated prior periods to conform to the new guidance. Adoption of the lease standard has a material impact on the Company’s Condensed Consolidated Balance Sheets but does not have a material impact on the Condensed Consolidated Statements of Earnings or the Condensed Consolidated Statements of Cash Flows. Effective January 1, 2019, the Company accounts for contracts that convey the use and control of identified assets for a period of time as leases. The Company classifies leases as operating or financing by evaluating the terms of the lease agreement. Agreements under which the Company is likely to utilize substantially all of the economic value or life of the asset or which the Company is likely to own at the end of the lease term, either through purchase or transfer of ownership, are classified as financing leases. Leases not meeting these criteria are accounted for as operating leases. Agreements under which the Company is a lessor are insignificant. Leases with terms that are expected to exceed one year are recognized on the Company’s Condensed Consolidated Balance Sheets by recording a lease liability and corresponding right-of-use asset. PNMR, PNM, and TNMP determine present value for their leases using their incremental borrowing rates at the commencement date of the lease or, when readily available, the rate implicit in the agreement. However, in most cases the implicit interest rate is not available in the Company’s lease agreements. Operating lease expense is recognized within operating expenses according to the use of the asset on a straight-line basis. Financing lease costs are recognized by amortizing the right-of-use asset on a straight-line basis and by recording interest expense on the lease liability. Financing lease right-of-use assets amortization is reflected in depreciation and amortization and interest on financing lease liabilities is reflected as interest charges on the Company’s Condensed Consolidated Statements of Earnings. PVNGS PNM leases interests in Units 1 and 2 of PVNGS. The PVNGS leases were entered into in 1985 and 1986 and initially were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Following procedures set forth in the PVNGS leases, PNM notified four of the lessors under the Unit 1 leases and one lessor under the Unit 2 lease that it would elect to renew those leases on the expiration date of the original leases. The four Unit 1 leases now expire on January 15, 2023 and the one Unit 2 lease now expires on January 15, 2024. The annual lease payments during the renewal periods aggregate $16.5 million for PVNGS Unit 1 and $1.6 million for Unit 2. The terms of each of the extended leases do not provide for additional renewal options beyond their currently scheduled expiration dates. PNM has the option to purchase the assets underlying each of the extended leases at their fair market value or to return the lease interests to the lessors on the expiration dates. Under the terms of the extended leases, PNM has until January 15, 2020 for the Unit 1 leases and January 15, 2021 for the Unit 2 lease to provide notices to the lessors of PNM’s intent to exercise the purchase options or to return the leased assets to the lessors. PNM’s elections are independent for each lease and are irrevocable. In the proceeding addressing PNM’s 2017 IRP (Note 12), PNM agreed to promptly notify the NMPRC of a decision to extend the Unit 1 or 2 leases, or to exercise its option to purchase the leased assets at fair market value upon the expiration of leases. If PNM elects to exercise its purchase option under any of the leases, the leases provide an appraisal process to determine fair market value. If PNM elects to return the assets underlying the extended leases, PNM will retain certain obligations related to PNVGS, including costs to decommission the facility. PNM would seek to recover its undepreciated investments at the end of the PVNGS leases as well as any future obligations related to PNM’s leased capacity from NM retail customers. Any transfer of the assets underlying the leases will be required to comply with NRC licensing requirements. See Note 12 for information concerning the NMPRC’s treatment of PNM’s purchase of assets underlying 64.1 MW and extension of 114.6 MW of leased capacity in PVNGS Unit 2, the NM Supreme Court’s decision regarding PNM’s appeal of certain matters in the NM 2015 Rate Case, as well as information concerning a joint petition to investigate PNM’s option to purchase additional assets underlying the extended leased capacity in PVNGS. Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the lessors and take title to the leased interests. If such an event had occurred as of June 30, 2019, amounts due to the lessors under the circumstances described above would be up to $161.2 million, payable on July 15, 2019 in addition to the scheduled lease payments due on July 15, 2019. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid. Land Easements and Rights-of-Ways Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million, subject to adjustment each year based on the Consumer Price Index, through 2029. PNM’s April 2018 payment for the amount due under the Navajo Nation right-of-way lease was $6.9 million, which included amounts due under the Consumer Price Index adjustment, and was used to determine PNM’s operating lease liability as of January 1, 2019 and is included in the table of future lease payments shown below. Changes in the Consumer Price Index subsequent to January 1, 2019 are considered variable lease payments. Fleet Vehicles and Equipment As of December 31, 2018, all of the Company’s leases of fleet vehicles and equipment are classified as operating leases. Historically, the Company has utilized substantially all of the economic value of its fleet and equipment leases by the end of the lease term. The Company generally has the contractual ability to return its fleet vehicle and equipment leases to the lessor after one year provided the lessor can recover remaining amounts owed under the agreement from third-parties or through make-whole provisions in the contract but does not typically exercise this right. As a result, fleet vehicle and equipment leases commencing on or after January 1, 2019 are classified as financing leases. The Company’s fleet vehicle and equipment lease agreements include non-lease components for insignificant administrative and other costs that are billed over the life of the agreement. The Company has elected to combine these fees with the lease components of the agreement. Certain of the Company’s fleet vehicle and equipment leases contain residual value guarantees. At June 30, 2019, residual value guarantees on fleet vehicle and equipment leases are $0.5 million, $1.1 million, and $1.6 million for PNM, TNMP, and PNMR. Other The Company holds a number of office space and office equipment leases. The Company’s current office space leases, all of which existed as of December 31, 2018, are classified as operating leases. These agreements include non-lease components for costs such as common area maintenance fees, which the Company has elected to combine with the lease component of the agreements. Certain of the Company’s office space leases are held between the Company’s consolidated subsidiaries and have been eliminated on consolidation. See Note 15. The Company’s office equipment leases are primarily for copiers and other graphics equipment. The Company classifies its office equipment leases existing as of December 31, 2018 as operating leases. Office equipment leases commencing on or after January 1, 2019 are classified as financing leases. Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below:
As discussed above, the Company classifies its fleet vehicle and equipment leases and its office equipment leases commencing on or after January 1, 2019 as financing leases. Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:
Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:
Information for the components of lease expense is as follows:
Supplemental cash flow information related to the Company’s leases is as follows:
Excluded from the operating and financing cash paid for leases above are $0.7 million and $0.1 million at PNM, $1.3 million and $0.1 million at TNMP, and $2.0 million and $0.2 million at PNMR. These capitalized costs are reflected as investing activities on the Company’s Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2019. Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below:
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Income Taxes |
6 Months Ended |
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Jun. 30, 2019 | |
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 made 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 eliminated federal bonus depreciation for utilities, limited interest deductibility for non-utility businesses and limited the deductibility of officer compensation. During 2018, the IRS issued additional guidance related to certain officer compensation, as well as proposed regulations on interest deductibility that provide a 10% “de minimis” exception that allows entities with predominantly regulated activities to fully deduct interest expenses. In addition, the IRS issued proposed regulations interpreting Tax Act amendments to depreciation provisions of the Internal Revenue Code that allow the Company to claim a bonus depreciation deduction on certain construction projects placed in service subsequent to the third quarter of 2017. See additional discussion of the impacts of the Tax Act in Note 18 of the Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. Beginning February 2018, PNM’s NM 2016 Rate Case reflects the reduction in the federal corporate income tax rate, including amortization of excess deferred federal income taxes that are being returned to customers over an average of twenty-three years; and reductions in the New Mexico corporate income tax rate, including amortization of excess deferred state income taxes that are being returned to customers over a three-year period. The approved settlement in the TNMP 2018 Rate Case includes a reduction in customer rates to reflect the impacts of the Tax Act beginning on January 1, 2019. See additional discussion of PNM’s NM 2016 Rate Case and TNMP’s 2018 Rate Case in Note 12. 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 June 30, 2019, PNMR, PNM, and TNMP estimated their effective income tax rates for the year ended December 31, 2019 would be 8.93%, 11.20%, and 8.81%. 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 and the amortization of excess deferred federal income taxes as ordered by the PUCT in TNMP’s 2018 Rate Case. During the three and six months ended June 30, 2019, income tax expense calculated by applying the expected annual effective income tax rate to earnings before income taxes was further reduced by excess tax benefits related to stock awards of $0.1 million and $0.8 million for PNMR, of which less than $0.1 million and $0.5 million was allocated to PNM and less than $0.1 million and $0.2 million was allocated to TNMP.
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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. PNM also provides interconnection services to PNMR Development (Note 9) and NMRD. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, TNMP, and NMRD:
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Goodwill |
6 Months Ended |
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Jun. 30, 2019 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill | Goodwill The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM. PNMR’s reporting units that currently have goodwill are PNM and TNMP. Additional information concerning the Company’s goodwill is contained in Note 19 of Notes to Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K. GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price has occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A quantitative analysis is not required if, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, GAAP currently requires the entity to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations. As further discussed under New Accounting Pronouncements in Note 1, a new accounting pronouncement changes how a goodwill impairment is determined by eliminating the second step of the quantitative impairment analysis. For its annual evaluations performed as of April 1, 2018, PNMR performed a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit. For the quantitative analyses, a discounted cash flow methodology was primarily used to estimate the fair value of the PNM reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for the reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The April 1, 2018 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 19%. The 2018 qualitative analysis for the TNMP reporting unit was performed by considering changes in expectations of future financial performance since the April 1, 2016 quantitative analysis that indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 32% as well as by considering the results of the April 1, 2017 qualitative analysis. The 2018 analysis considered events specific to TNMP such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12. Both the PNM quantitative analysis and the TNMP qualitative analysis considered market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2018 carrying values of PNM or TNMP exceed their fair values. For its annual evaluations performed as of April 1, 2019, PNMR performed qualitative analyses for both the PNM and TNMP reporting units. The qualitative analysis was performed by considering changes in the Company’s expectations of future financial performance since the April 1, 2018 quantitative analysis performed for PNM, as well as the quantitative analysis performed for TNMP at April 1, 2016 and the qualitative analyses through April 1, 2018. This analysis considered Company specific events such as the potential impacts of legal and regulatory matters discussed in Note 11 and Note 12, including potential outcomes in PNM’s SJGS Abandonment Application, the impacts of the NM Supreme Court’s decision in the appeal of the NM 2015 Rate Case, and other potential impacts of changes in PNM’s resource needs based on PNM’s 2017 IRP. The qualitative analysis also considered market and macroeconomic factors including changes in growth rates, changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying value of its reporting units. Based on an evaluation of these and other factors, the Company determined it was not more likely than not that the April 1, 2019 carrying values of PNM or TNMP exceeded their fair values. |
Significant Accounting Policies and Responsibility for Financial Statements (Policies) |
6 Months Ended |
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Jun. 30, 2019 | |
Accounting Policies [Abstract] | |
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. |
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 2016-13 – Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, which changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in certain debt securities, by requiring immediate recognition of estimated credit losses expected to occur over the remaining lives of the assets. In November 2018, the FASB clarified that receivables arising from operating leases are not within the scope of Topic 326 for assets measured at amortized costs. Instead, impairments of receivables arising from operating leases should be accounted for in accordance with Topic 842. In May 2019, the FASB issued transition relief by providing an option to irrevocably elect the fair value option for certain financial assets previously measured at amortized cost. The Company anticipates adopting ASU 2016-13 as of January 1, 2020, its required effective date. 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 2018-13 – Fair Value Measurements (Topic 820) Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurements In August 2018, the FASB issued ASU 2018-13 to improve fair value disclosures. ASU 2018-13 eliminates certain disclosure requirements related to transfers between Levels 1 and 2 of the fair value hierarchy and the requirement to disclose the valuation process for Level 3 fair value measurements. ASU 2018-13 also amends certain disclosure requirements for investments measured at net asset value and requires new disclosures for Level 3 investments, including a new requirement to disclose changes in unrealized gains or losses recorded in OCI related to Level 3 fair value measurements. ASU 2018-13 is effective for the Company beginning on January 1, 2020, and permits entities to adopt all or certain elements of the new guidance prior to its effective date. ASU 2018-13 requires retrospective application, except for the new disclosures related to Level 3 investments which are to be applied prospectively. As discussed in Note 9 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 7, PNM and TNMP have investment securities in trusts for decommissioning, reclamation, pension benefits, and other postretirement benefits, which are measured at fair value. Certain investments in these trusts are measured at net asset value per share. These trusts also hold Level 3 investments. The Company is evaluating the requirements of ASU 2018-13, but does not anticipate it will have a significant impact on the Company’s fair value disclosures. Accounting Standards Update 2018-14 – Compensation - Retirement Benefits - Defined Benefit Plans (Topic 715) Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans In August 2018, the FASB issued ASU 2018-14 to improve benefit plan sponsors’ disclosures for defined benefit pension and other post-employment benefit plans. ASU 2018-14 removes the requirement to disclose the amounts in other comprehensive income expected to be recognized as benefit cost over the next fiscal year and the requirement to disclose the impact of a one-percentage-point change in the assumed health care cost trend rate; clarifies the disclosure requirements for plans with assets that are less than their projected benefit, or accumulated benefit obligation; and requires significant gains and losses affecting benefit obligations during the period be disclosed. ASU 2018-14 is effective for the Company on December 31, 2020, although early adoption is permitted, and requires retrospective application. As discussed in Note 11 of the Notes to the Consolidated Financial Statements in the 2018 Annual Reports on Form 10-K and in Note 10, PNM and TNMP maintain qualified defined benefit, other postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The Company is evaluating the requirements of ASU 2018-14 but does not anticipate these changes will have a significant impact on the Company’s defined benefit and other postretirement benefit plan disclosures. Accounting Standards Update 2018-15 – Intangibles - Goodwill and Other - Internal Use Software (Topic 350): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15 to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for implementation costs incurred to develop or obtain internal-use software. Under ASU 2018-15, entities are required to capitalize implementation costs for hosting arrangements if those costs meet the capitalization requirements for internal-use software arrangements. ASU 2018-15 requires entities to present cash flows, capitalized costs, and amortization expense in the same financial statement line items as other costs incurred for such hosting arrangements. ASU 2018-15 is effective for the Company on January 1, 2020, although early adoption is permitted, and allows entities to apply the new requirements retrospectively or prospectively. The Company is in the process of analyzing the impacts of this new standard. Accounting Standards Update 2018-18 – Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 In November 2018, the FASB issued ASU 2018-18 to clarify transactions between collaborative arrangement participants that should be recognized as revenue under Topic 606. ASU 2018-18 is effective for the Company on January 1, 2020, although early adoption is permitted, and requires retrospective application. The Company has collaborative arrangements related to its interests in SJGS, Four Corners, PVNGS, and Luna. The Company believes its current accounting practices comply with the requirements of ASU 2018-18 but is in the process of analyzing the impacts of the new standard. GAAP requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as operating cash flows when used to reduce income taxes payable.
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Variable Interest Entities |
Significant Accounting Policies and Responsibility for Financial Statements (Tables) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Marketable Securities | Summarized financial information for NMRD is as follows:
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Segment Information (Tables) |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Other Comprehensive Income (Loss) | Information regarding accumulated other comprehensive income (loss) for the six months ended June 30, 2019 and 2018 is as follows:
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Earnings Per Share (Tables) |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Computation of Earnings Per Share | Information regarding the computation of earnings per share is as follows:
(1) Due to the loss in the three and six months ended June 30, 2019, no potentially dilutive shares are reflected in the average number of shares used to compute net earnings (loss) per share of common stock since any impact would be anti-dilutive. At June 30, 2019, PNMR’s potentially dilutive shares consist of stock options and restricted stock (see Note 8).
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Electric Operating Revenues (Tables) |
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disaggregation of Revenue | A disaggregation of revenues from contracts with customers by the type of customer is presented in the table below. The table also reflects alternative revenue program revenues (“ARP”) and other revenues.
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Contract with Customer, Asset and Liability | 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) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summarized Financial Information | Summarized financial information for Valencia is as follows:
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Fair Value of Derivative and Other Financial Instruments (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 presented in the following line items on the Condensed Consolidated Balance Sheets:
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Effect of Mark-to-Market on Earnings, Excluding Tax Effects | The effects of mark-to-market commodity derivative instruments on PNM’s revenues and cost of energy during the three and six months ended June 30, 2019 and 2018 were less than $0.1 million. 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 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 $(0.8) million and $2.6 for the three and six months ended June 30, 2019 and $(2.6) million and $(3.8) million for the three and six months ended June 30, 2018.
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Investments Classified by Contractual Maturity Date | At June 30, 2019, the available-for-sale debt securities held by PNM, had the following final maturities:
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Schedule of Investments | 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 debt securities.
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Summary of Level 3 Measurements | A reconciliation of the changes in Level 3 fair value measurements is as follows:
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Schedule of Carrying Amount and Fair Value of Items Not Recorded at Fair Value | The carrying amounts and fair values of long-term debt, which is not recorded at fair value on the Condensed Consolidated Balance Sheets, are presented below:
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Stock-Based Compensation (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share-based Payment Arrangement [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Activity | 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 six months ended June 30, 2019:
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 (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Maturities of Long-term Debt | Information concerning the funding dates, maturities and interest rates on the TNMP 2019 Bonds is as follows:
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Schedule of Short-term Debt | Short-term debt outstanding consisted of:
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Pension and Other Postretirement Benefit Plans (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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:
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Regulatory and Rate Matters (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulated Operations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Rate Increases for Transmission Costs | The following sets forth TNMP’s recent interim transmission cost rate increases:
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Lease Commitments (Tables) |
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2019 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Leases [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assets and Liabilities, Lessee | Information related to the Company’s financing leases recorded on the Condensed Consolidated Balance Sheets is presented below:
Information concerning the weighted average remaining lease terms and the weighted average discount rates used to determine the Company’s lease liabilities is presented below:
Information related to the Company’s operating leases recorded on the Condensed Consolidated Balance Sheets, including amounts recognized upon adoption of ASU 2016-02, is presented below:
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Lease, Cost | Information for the components of lease expense is as follows:
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Schedule of Leases, Supplemental Cash Flows | Supplemental cash flow information related to the Company’s leases is as follows:
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Lessee, Operating Lease, Liability, Maturity | Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below:
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Finance Lease, Liability, Maturity | Future expected lease payments as of June 30, 2019 and December 31, 2018 are shown below:
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Schedule of Future Minimum Rental Payments for Operating Leases |
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Related Party Transactions (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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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:
|
Significant Accounting Policies and Responsibility for Financial Statements Summarized Financial Information (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | |||
---|---|---|---|---|---|
Jun. 30, 2019 |
Jun. 30, 2018 |
Jun. 30, 2019 |
Jun. 30, 2018 |
Dec. 31, 2018 |
|
Results of Operations | |||||
Operating revenues | $ 330,228 | $ 352,313 | $ 679,872 | $ 670,191 | |
Financial Position | |||||
Net property, plant, and equipment | 202,991 | 202,991 | $ 194,427 | ||
Total assets | 7,048,667 | 6,750,089 | 7,048,667 | 6,750,089 | 6,865,551 |
Owners’ equity | (1,612,148) | (1,612,148) | (1,688,382) | ||
NMRD | |||||
Results of Operations | |||||
Operating revenues | 1,103 | 1,098 | 1,828 | 1,509 | |
Operating expenses | 655 | 657 | 1,451 | 1,006 | |
Net Earnings (Loss) Attributable to PNMR | 448 | $ 441 | 377 | $ 503 | |
Financial Position | |||||
Current assets | 2,733 | 2,733 | 2,581 | ||
Net property, plant, and equipment | 77,804 | 77,804 | 50,784 | ||
Total assets | 80,537 | 80,537 | 53,365 | ||
Current liabilities | 533 | 533 | 237 | ||
Owners’ equity | $ 80,004 | $ 80,004 | $ 53,128 |
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands |
3 Months Ended | 6 Months Ended | ||||
---|---|---|---|---|---|---|
Jun. 30, 2019 |
Jun. 30, 2018 |
Jun. 30, 2019 |
Jun. 30, 2018 |
|||
Earnings Per Share [Abstract] | ||||||
Net Earnings Available for PNM Common Stock | $ (75,914) | $ 38,208 | $ (57,214) | $ 53,198 | ||
Average Number of Common Shares: | ||||||
Outstanding during period (in shares) | 79,654 | 79,654 | 79,654 | 79,654 | ||
Vested awards of restricted stock (in shares) | [1] | 263 | 211 | 251 | 208 | |
Average Shares – Basic (in shares) | 79,917 | 79,865 | 79,905 | 79,862 | ||
Dilutive Effect of Common Stock Equivalents:(1) | ||||||
Stock options and restricted stock (in shares) | 0 | 114 | 0 | 134 | ||
Average Shares – Diluted (in shares) | 79,917 | 79,979 | 79,905 | 79,996 | ||
Net Earnings (Loss) Per Share of Common Stock: | ||||||
Basic (in dollars per share) | $ (0.95) | $ 0.48 | $ (0.72) | $ 0.67 | ||
Diluted (in dollars per share) | $ (0.95) | $ 0.48 | $ (0.72) | $ 0.67 | ||
|
Electric Operating Revenues - Narrative (Details) |
Jun. 30, 2019
USD ($)
utility
|
Dec. 31, 2018
USD ($)
|
---|---|---|
Disaggregation of Revenue [Line Items] | ||
Number of regulated utilities | utility | 2 | |
Contract assets | $ 0 | $ 0 |
Customer contracts | PNM | ||
Disaggregation of Revenue [Line Items] | ||
Accounts receivable | $ 52,700,000 | $ 61,700,000 |
Electric Operating Revenues - Changes in contract liabilities (Details) $ in Thousands |
6 Months Ended |
---|---|
Jun. 30, 2019
USD ($)
| |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | $ 349 |
Consideration received in advance of service to be provided | 5,674 |
Deferred revenue earned | (3,035) |
Ending balance | 2,988 |
PNM | |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | 349 |
Consideration received in advance of service to be provided | 4,157 |
Deferred revenue earned | (2,259) |
Ending balance | 2,247 |
TNMP | |
Change In Contract With Customer Liability [Roll Forward] | |
Beginning balance | 0 |
Consideration received in advance of service to be provided | 1,517 |
Deferred revenue earned | (776) |
Ending balance | $ 741 |
Fair Value of Derivative and Other Financial Instruments - Statement of Earnings Information (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2019 |
Jun. 30, 2018 |
Jun. 30, 2019 |
Jun. 30, 2018 |
|
PNM | Designated as Hedging Instrument | Commodity derivatives | Cost of energy | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Total gain | $ 0.1 | $ 0.1 | $ 0.1 | $ 0.1 |
Fair Value of Derivative and Other Financial Instruments - Margin, Notional Amounts and Credit Rating (Details) MWh in Thousands, MMBTU in Thousands |
6 Months Ended | 12 Months Ended |
---|---|---|
Jun. 30, 2019
USD ($)
MWh
MMBTU
|
Dec. 31, 2018
USD ($)
MWh
MMBTU
|
|
Derivative [Line Items] | ||
Contract in a liability position | $ | $ 0 | $ 0 |
PNM | Commodity derivatives | Fair value hedging | Buy | ||
Derivative [Line Items] | ||
Economic Hedges (in mmbtu and mwh) | MMBTU | 565 | 100 |
PNM | Commodity derivatives | Fair value hedging | Sell | ||
Derivative [Line Items] | ||
Economic Hedges (in mmbtu and mwh) | MWh | 42 | 0 |
Fair Value of Derivative and Other Financial Instruments - Investments in NDT (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2019 |
Jun. 30, 2018 |
Jun. 30, 2019 |
Jun. 30, 2018 |
|
Equity securities: | ||||
Net gains from equity securities sold | $ 2,774 | $ 2,502 | $ 4,161 | $ 5,330 |
Net gains (losses) from equity securities still held | 303 | (443) | 9,905 | (307) |
Total net gains on equity securities | 3,077 | 2,059 | 14,066 | 5,023 |
Available-for-sale debt securities: | ||||
Net gains (losses) on debt securities | 1,522 | (3,729) | 4,547 | (6,405) |
Net gains (losses) on investment securities | $ 4,599 | $ (1,670) | $ 18,613 | $ (1,382) |
Fair Value of Derivative and Other Financial Instruments - Maturities of Debt Securities (Details) - PNMR and PNM $ in Thousands |
Jun. 30, 2019
USD ($)
|
---|---|
Available-for-Sale | |
Within 1 year | $ 20,868 |
After 1 year through 5 years | 75,642 |
After 5 years through 10 years | 67,572 |
After 10 years through 15 years | 12,886 |
After 15 years through 20 years | 11,747 |
After 20 years | 34,246 |
Available-for-sale debt securities | $ 222,961 |
Fair Value of Derivative and Other Financial Instruments - Reconciliation of changes in Level 3 fair value measurements (Details) - Corporate Debt - Level 3 - USD ($) $ in Thousands |
6 Months Ended | |
---|---|---|
Jun. 30, 2019 |
Jun. 30, 2018 |
|
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||
Beginning balance | $ 2,156 | $ 0 |
Actual return on assets sold during the period | (48) | (4) |
Actual return on assets still held at period end | 63 | (5) |
Purchases | 1,422 | 4,011 |
Sales | (784) | (1,011) |
Ending balance | $ 2,809 | $ 2,991 |
Financing - TNMP 2019 Bonds (Details) - TNMP - Mortgages - USD ($) |
Jul. 01, 2019 |
Mar. 29, 2019 |
Feb. 26, 2019 |
---|---|---|---|
First Mortgage Bonds 3.79 Percent Due 2034 | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 75,000,000.0 | ||
Stated interest rate | 3.79% | ||
First Mortgage Bonds 3.92 Percent Due 2039 | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 75,000,000.0 | ||
Stated interest rate | 3.92% | ||
First Mortgage Bonds 4.06 Percent Due 2044 | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 75,000,000.0 | ||
Stated interest rate | 4.06% | ||
TNMP 2019 Bond Purchase Agreement | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 225,000,000.0 | $ 305,000,000.0 | |
Stated interest rate | 400.00% | ||
Subsequent event | TNMP 2019 Bond Purchase Agreement | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 305,000,000.0 | ||
Subsequent event | First Mortgage Bonds 3.60 Percent Due 2029 | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount | $ 80,000,000.0 | ||
Stated interest rate | 3.60% |
Commitments and Contingencies - Nuclear Spent Fuel and Waste Disposal (Details) - PNM - Nuclear spent fuel and waste disposal - Palo Verde Nuclear Generating Station - USD ($) $ in Millions |
Jun. 30, 2019 |
Dec. 31, 2018 |
---|---|---|
Public Utilities, Commitments And Contingencies [Line Items] | ||
Estimate of possible loss | $ 57.7 | |
Other deferred credits | ||
Public Utilities, Commitments And Contingencies [Line Items] | ||
Loss contingency accrual | $ 12.7 | $ 12.4 |
Commitments and Contingencies - The Energy Transition Act (Details) - Electric-Generation Portfolio Standard - Energy Transition Act |
Mar. 22, 2019 |
---|---|
Required Percentage by 2020 | |
Public Utilities, Commitments And Contingencies [Line Items] | |
Renewable energy, percentage | 0.20 |
Required Percentage by 2025 | |
Public Utilities, Commitments And Contingencies [Line Items] | |
Renewable energy, percentage | 0.40 |
Required Percentage by 2030 | |
Public Utilities, Commitments And Contingencies [Line Items] | |
Renewable energy, percentage | 0.50 |
Required Percentage by 2040 | |
Public Utilities, Commitments And Contingencies [Line Items] | |
Renewable energy, percentage | 0.80 |
Required Percentage by 2045 | |
Public Utilities, Commitments And Contingencies [Line Items] | |
Renewable energy, percentage | 1 |
Regulatory and Rate Matters - SJGS Abandonment Application (Details) - Subsequent event - San Juan Generating Station - PNM $ in Millions |
Jul. 01, 2019
USD ($)
scenario
MW
|
---|---|
Public Utilities, General Disclosures [Line Items] | |
Number of megawatts in natural gas-fired peaking plant (in megawatts) | MW | 280 |
Number of megawatts in battery storage facilities (in megawatts) | MW | 70 |
Solar generation capacity (in megawatts) | MW | 350 |
Number of megawatts in battery storage facilities, replacement resource scenario (in megawatts) | MW | 60 |
Number of replacement resource scenarios | scenario | 3 |
Request issuance of energy transition bonds | $ 361.0 |
Forecasted undepreciated investment | 283.0 |
Plant decommissioning and coal mine reclamation costs | 28.6 |
Upfront financing costs | 9.6 |
Severance costs | 20.0 |
Proceeds from securitization bonds | $ 19.8 |
Regulatory and Rate Matters - TNMP Narrative (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
---|---|---|---|---|---|---|---|
Dec. 20, 2018 |
May 30, 2018 |
Jun. 30, 2018 |
Jun. 30, 2018 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Mar. 01, 2019 |
|
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Unrecovered investment revenue | $ 20.2 | ||||||
TNMP | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Net regulatory liability | $ 37.8 | ||||||
Reduction to revenue | $ 1.2 | $ 2.7 | $ 5.4 | ||||
Energy efficiency cost recovery, requested change amount | 5.9 | $ 5.6 | |||||
Energy efficiency cost recovery, requested bonus | 0.8 | $ 0.8 | |||||
TNMP | 2018 TNMP Rate Case | |||||||
Public Utilities, Commitments And Contingencies [Line Items] | |||||||
Requested rate increase (decrease) | $ 10.0 | $ 25.9 | |||||
Requested return on equity | 9.65% | 10.50% | |||||
Requested cost of debt | 6.44% | 7.20% | |||||
Requested debt capital structure | 55.00% | 50.00% | |||||
Requested equity capital structure | 45.00% | 50.00% | |||||
Investments excluded from rate request | $ 10.6 | ||||||
Refund of federal income tax rates period | 5 years |
Regulatory and Rate Matters - Transmission Cost of Service Rates (Details) - TNMP - USD ($) $ in Millions |
Jul. 23, 2019 |
Mar. 21, 2019 |
Mar. 27, 2018 |
Sep. 13, 2017 |
Mar. 14, 2017 |
---|---|---|---|---|---|
Transmission Cost of Service Rates | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved Increase in Rate Base | $ 30.2 | ||||
Annual Increase in Revenue | $ 4.8 | ||||
PUCT | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Requested rate increase (decrease) | $ 111.8 | $ 32.0 | $ 27.5 | ||
Proposed increase (decrease) in revenues | $ 14.3 | $ 0.6 | $ 4.7 | ||
Subsequent event | Transmission Cost of Service Rates | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved Increase in Rate Base | $ 21.9 | ||||
Annual Increase in Revenue | $ 3.3 |
Lease Commitments - Operating Lease Balance Sheet Information (Details) - USD ($) $ in Thousands |
Jun. 30, 2019 |
Jan. 01, 2019 |
---|---|---|
Operating leases: | ||
Operating lease assets, net of amortization | $ 143,876 | $ 157,440 |
Current portion of operating lease liabilities | 27,396 | 25,189 |
Long-term portion of operating lease liabilities | 116,464 | 135,174 |
PNM | ||
Operating leases: | ||
Operating lease assets, net of amortization | 132,057 | 143,816 |
Current portion of operating lease liabilities | 24,092 | 21,589 |
Long-term portion of operating lease liabilities | 107,741 | 124,891 |
TNMP | ||
Operating leases: | ||
Operating lease assets, net of amortization | 11,409 | 12,942 |
Current portion of operating lease liabilities | 2,913 | 3,132 |
Long-term portion of operating lease liabilities | $ 8,403 | $ 9,787 |
Lease Commitments - Finance Lease Balance Sheet Information (Details) $ in Thousands |
Jun. 30, 2019
USD ($)
|
---|---|
Financing leases: | |
Non-utility property | $ 4,821 |
Accumulated depreciation | (282) |
Non-utility property, net | 4,539 |
Other current liabilities | 789 |
Other deferred credits | 3,438 |
PNM | |
Financing leases: | |
Non-utility property | 2,516 |
Accumulated depreciation | (143) |
Non-utility property, net | 2,373 |
Other current liabilities | 381 |
Other deferred credits | 1,678 |
TNMP | |
Financing leases: | |
Non-utility property | 2,305 |
Accumulated depreciation | (139) |
Non-utility property, net | 2,166 |
Other current liabilities | 408 |
Other deferred credits | $ 1,760 |
Lease Commitments - Schedule of Weighted Average Remaining Lease Terms and Discount Rates (Details) |
Jun. 30, 2019 |
---|---|
Weighted average remaining lease term (In years): | |
Operating leases | 6 years 6 months 18 days |
Financing leases | 5 years 5 months 15 days |
Weighted average discount rate: | |
Operating leases | 3.87% |
Financing leases | 4.24% |
PNM | |
Weighted average remaining lease term (In years): | |
Operating leases | 6 years 9 months |
Financing leases | 5 years 5 months 23 days |
Weighted average discount rate: | |
Operating leases | 3.87% |
Financing leases | 4.22% |
TNMP | |
Weighted average remaining lease term (In years): | |
Operating leases | 4 years 5 months 26 days |
Financing leases | 5 years 5 months 12 days |
Weighted average discount rate: | |
Operating leases | 3.90% |
Financing leases | 4.26% |
Income Taxes (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | |
---|---|---|---|
May 23, 2017 |
Jun. 30, 2019 |
Jun. 30, 2019 |
|
Income Tax Contingency [Line Items] | |||
Effective tax rate | 8.93% | ||
Tax benefits related to stock awards | $ 0.1 | $ 0.8 | |
TNMP | |||
Income Tax Contingency [Line Items] | |||
Effective tax rate | 8.81% | ||
Tax benefits related to stock awards | 0.1 | $ 0.2 | |
PNM | |||
Income Tax Contingency [Line Items] | |||
Effective tax rate | 11.20% | ||
Tax benefits related to stock awards | $ 0.1 | $ 0.5 | |
NMPRC | |||
Income Tax Contingency [Line Items] | |||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 23 years | ||
NMPRC | PNM | |||
Income Tax Contingency [Line Items] | |||
Period of time for proposed return to customers the benefit of the reduction in New Mexico's corporate income tax rate | 3 years |
Goodwill (Details) - USD ($) $ in Thousands |
Jun. 30, 2019 |
Dec. 31, 2018 |
Jun. 30, 2018 |
Apr. 01, 2018 |
---|---|---|---|---|
Goodwill [Line Items] | ||||
Goodwill | $ 278,297 | $ 278,297 | $ 278,297 | |
PNM | ||||
Goodwill [Line Items] | ||||
Goodwill | 51,632 | 51,632 | $ 51,600 | |
Goodwill fair value exceeded by its carrying value | 19.00% | |||
TNMP | ||||
Goodwill [Line Items] | ||||
Goodwill | $ 226,665 | $ 226,665 | $ 226,700 | |
Goodwill fair value exceeded by its carrying value | 32.00% |
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