[X] | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File | Name of Registrants, State of Incorporation, | I.R.S. Employer | ||
Number | Address and Telephone Number | Identification No. | ||
001-32462 | PNM Resources, Inc. | 85-0468296 | ||
(A New Mexico Corporation) | ||||
414 Silver Ave. SW | ||||
Albuquerque, New Mexico 87102-3289 | ||||
(505) 241-2700 | ||||
001-06986 | Public Service Company of New Mexico | 85-0019030 | ||
(A New Mexico Corporation) | ||||
414 Silver Ave. SW | ||||
Albuquerque, New Mexico 87102-3289 | ||||
(505) 241-2700 | ||||
002-97230 | Texas-New Mexico Power Company | 75-0204070 | ||
(A Texas Corporation) | ||||
577 N. Garden Ridge Blvd. | ||||
Lewisville, Texas 75067 | ||||
(972) 420-4189 |
PNM Resources, Inc. (“PNMR”) | YES | ü | NO | ||
Public Service Company of New Mexico (“PNM”) | YES | ü | NO | ||
Texas-New Mexico Power Company (“TNMP”) | YES | NO | ü |
PNMR | YES | ü | NO | ||
PNM | YES | ü | NO | ||
TNMP | YES | ü | NO |
Large accelerated filer | Accelerated filer | Non-accelerated filer | Smaller Reporting Company | |||||||||||||
PNMR | ü | |||||||||||||||
PNM | ü | |||||||||||||||
TNMP | ü |
Page No. | |
Definitions: | ||
Afton | Afton Generating Station | |
AFUDC | Allowance for Funds Used During Construction | |
ALJ | Administrative Law Judge | |
AMS | Advanced Meter System | |
AOCI | Accumulated Other Comprehensive Income | |
APS | Arizona Public Service Company, which is the operator and a co-owner of PVNGS and Four Corners | |
BACT | Best Available Control Technology | |
BART | Best Available Retrofit Technology | |
BHP | BHP Billiton, Ltd, the parent of SJCC | |
Board | Board of Directors of PNMR | |
BTU | British Thermal Unit | |
CAA | Clean Air Act | |
CCB | Coal Combustion Byproducts | |
CCN | Certificate of Convenience and Necessity | |
CO2 | Carbon Dioxide | |
D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit | |
Delta | Delta-Person Generating Station | |
DOE | United States Department of Energy | |
DOI | United States Department of Interior | |
EIB | New Mexico Environmental Improvement Board | |
EIP | Eastern Interconnection Project | |
EPA | United States Environmental Protection Agency | |
ERCOT | Electric Reliability Council of Texas | |
ESA | Endangered Species Act | |
Exchange Act | Securities Exchange Act of 1934 | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FIP | Federal Implementation Plan | |
Four Corners | Four Corners Power Plant | |
FPPAC | Fuel and Purchased Power Adjustment Clause | |
GAAP | Generally Accepted Accounting Principles in the United States of America | |
Gallup | City of Gallup, New Mexico | |
GHG | Greenhouse Gas Emissions | |
GWh | Gigawatt hours | |
IBEW | International Brotherhood of Electrical Workers | |
IRP | Integrated Resource Plan | |
IRS | Internal Revenue Service | |
KW | Kilowatt | |
KWh | Kilowatt Hour | |
Lordsburg | Lordsburg Generating Station | |
Luna | Luna Energy Facility | |
MD&A | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
MMBTU | Million BTUs | |
Moody’s | Moody’s Investor Services, Inc. | |
MW | Megawatt | |
MWh | Megawatt Hour |
NAAQS | National Ambient Air Quality Standards | |
Navajo Acts | Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act | |
NDT | Nuclear Decommissioning Trusts for PVNGS | |
NEC | Navopache Electric Cooperative, Inc. | |
NERC | North American Electric Reliability Council | |
Ninth Circuit | United States Court of Appeals for the Ninth Circuit | |
NMAG | New Mexico Attorney General | |
NMED | New Mexico Environment Department | |
NMIEC | New Mexico Industrial Energy Consumers Inc. | |
NMPRC | New Mexico Public Regulation Commission | |
NOx | Nitrogen Oxides | |
NOI | Notice of Inquiry | |
NOPR | Notice of Proposed Rulemaking | |
NRC | United States Nuclear Regulatory Commission | |
NSPS | New Source Performance Standards | |
NSR | New Source Review | |
OCI | Other Comprehensive Income | |
OPEB | Other Post Employment Benefits | |
OSM | United States Office of Surface Mining Reclamation and Enforcement | |
PNM | Public Service Company of New Mexico and Subsidiaries | |
PNM Revolving Credit Facility | PNM's $400.0 Million Unsecured Revolving Credit Facility | |
PNM Term Loan Agreement | PNM's $75.0 Million Unsecured Term Loan Facility | |
PNMR | PNM Resources, Inc. and Subsidiaries | |
PNMR Revolving Credit Facility | PNMR's $300.0 Million Unsecured Revolving Credit Facility | |
PNMR Term Loan Agreement | PNMR's $100.0 Million Unsecured Term Loan Facility | |
PPA | Power Purchase Agreement | |
PSD | Prevention of Significant Deterioration | |
PUCT | Public Utility Commission of Texas | |
PV | Photovoltaic | |
PVNGS | Palo Verde Nuclear Generating Station | |
RCRA | Resource Conservation and Recovery Act | |
RCT | Reasonable Cost Threshold | |
REA | New Mexico's Renewable Energy Act of 2004 | |
REC | Renewable Energy Certificates | |
REP | Retail Electricity Provider | |
RMC | Risk Management Committee | |
RPS | Renewable Energy Portfolio Standard | |
SCE | Southern California Edison Company | |
SCR | Selective Catalytic Reduction | |
SEC | United States Securities and Exchange Commission | |
SIP | State Implementation Plan | |
SJCC | San Juan Coal Company | |
SJGS | San Juan Generating Station | |
SNCR | Selective Non-Catalytic Reduction | |
SO2 | Sulfur Dioxide | |
SPS | Southwestern Public Service Company |
S&P | Standard and Poor’s Ratings Services | |
TECA | Texas Electric Choice Act | |
Tenth Circuit | United States Court of Appeals for the Tenth Circuit | |
TNMP | Texas-New Mexico Power Company and Subsidiaries | |
TNMP Revolving Credit Facility | TNMP's $75.0 Million Revolving Credit Facility | |
TNP | TNP Enterprises, Inc. and Subsidiaries | |
Tri-State | Tri-State Generation and Transmission Association, Inc. | |
Valencia | Valencia Energy Facility | |
VaR | Value at Risk | |
WEG | WildEarth Guardians |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands, except per share amounts) | |||||||||||||||
Electric Operating Revenues | $ | 347,599 | $ | 323,860 | $ | 665,263 | $ | 629,234 | |||||||
Operating Expenses: | |||||||||||||||
Cost of energy | 105,659 | 94,719 | 210,365 | 186,565 | |||||||||||
Administrative and general | 43,139 | 45,289 | 87,829 | 90,089 | |||||||||||
Energy production costs | 46,831 | 46,053 | 90,404 | 91,182 | |||||||||||
Depreciation and amortization | 41,639 | 41,054 | 82,446 | 79,468 | |||||||||||
Transmission and distribution costs | 17,148 | 17,565 | 33,443 | 33,814 | |||||||||||
Taxes other than income taxes | 15,316 | 14,074 | 32,205 | 29,281 | |||||||||||
Total operating expenses | 269,732 | 258,754 | 536,692 | 510,399 | |||||||||||
Operating income | 77,867 | 65,106 | 128,571 | 118,835 | |||||||||||
Other Income and Deductions: | |||||||||||||||
Interest income | 2,833 | 3,386 | 5,467 | 6,678 | |||||||||||
Gains (losses) on investments held by NDT | 3,272 | (795 | ) | 4,805 | 3,660 | ||||||||||
Other income | 2,555 | 1,862 | 4,265 | 4,507 | |||||||||||
Other (deductions) | (4,194 | ) | (2,716 | ) | (7,546 | ) | (7,268 | ) | |||||||
Net other income (deductions) | 4,466 | 1,737 | 6,991 | 7,577 | |||||||||||
Interest Charges | 30,616 | 30,198 | 61,914 | 59,765 | |||||||||||
Earnings before Income Taxes | 51,717 | 36,645 | 73,648 | 66,647 | |||||||||||
Income Taxes | 20,334 | 11,546 | 28,303 | 21,071 | |||||||||||
Net Earnings | 31,383 | 25,099 | 45,345 | 45,576 | |||||||||||
(Earnings) Attributable to Valencia Non-controlling Interest | (3,573 | ) | (3,455 | ) | (6,777 | ) | (6,720 | ) | |||||||
Preferred Stock Dividend Requirements of Subsidiary | (132 | ) | (132 | ) | (264 | ) | (264 | ) | |||||||
Net Earnings Attributable to PNMR | $ | 27,678 | $ | 21,512 | $ | 38,304 | $ | 38,592 | |||||||
Net Earnings Attributable to PNMR per Common Share: | |||||||||||||||
Basic | $ | 0.35 | $ | 0.27 | $ | 0.48 | $ | 0.48 | |||||||
Diluted | $ | 0.34 | $ | 0.27 | $ | 0.48 | $ | 0.48 | |||||||
Dividends Declared per Common Share | $ | 0.165 | $ | 0.145 | $ | 0.330 | $ | 0.290 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Net Earnings | $ | 31,383 | $ | 25,099 | $ | 45,345 | $ | 45,576 | |||||||
Other Comprehensive Income: | |||||||||||||||
Unrealized Gain on Investment Securities: | |||||||||||||||
Unrealized holding gains arising during the period, net of income tax (expense) of $(290), $(3,022), $(3,401) and $(10,437) | 443 | 4,611 | 5,190 | 15,924 | |||||||||||
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $2,185, $4,992, $2,714 and $8,538 | (3,333 | ) | (7,617 | ) | (4,140 | ) | (13,028 | ) | |||||||
Pension Liability Adjustment: | |||||||||||||||
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(631), $(476), $(1,262) and $(952) | 960 | 727 | 1,920 | 1,454 | |||||||||||
Fair Value Adjustment for Cash Flow Hedges: | |||||||||||||||
Change in fair market value, net of income tax (expense) benefit of $3, $40, $(1) and $99 | (6 | ) | (72 | ) | 2 | (178 | ) | ||||||||
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(18), $(16), $(35) and $(31) | 33 | 29 | 64 | 56 | |||||||||||
Total Other Comprehensive Income (Loss) | (1,903 | ) | (2,322 | ) | 3,036 | 4,228 | |||||||||
Comprehensive Income | 29,480 | 22,777 | 48,381 | 49,804 | |||||||||||
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,573 | ) | (3,455 | ) | (6,777 | ) | (6,720 | ) | |||||||
Preferred Stock Dividend Requirements of Subsidiary | (132 | ) | (132 | ) | (264 | ) | (264 | ) | |||||||
Comprehensive Income Attributable to PNMR | $ | 25,775 | $ | 19,190 | $ | 41,340 | $ | 42,820 |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings | $ | 45,345 | $ | 45,576 | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | 103,914 | 99,971 | |||||
Deferred income tax expense | 27,797 | 21,354 | |||||
Net unrealized (gains) losses on derivatives | 1,729 | 1,978 | |||||
Realized (gains) on investments held by NDT | (4,805 | ) | (3,660 | ) | |||
Stock based compensation expense | 3,198 | 1,435 | |||||
Other, net | 313 | (820 | ) | ||||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | (23,021 | ) | (20,901 | ) | |||
Materials, supplies, and fuel stock | (159 | ) | (5,250 | ) | |||
Other current assets | 3,870 | (12,021 | ) | ||||
Other assets | 6,356 | (6,659 | ) | ||||
Accounts payable | (7,424 | ) | (4,882 | ) | |||
Accrued interest and taxes | 93,077 | (9,944 | ) | ||||
Other current liabilities | (21,310 | ) | (3,016 | ) | |||
Proceeds from governmental grants | — | 21,567 | |||||
Other liabilities | (68,972 | ) | (83,432 | ) | |||
Net cash flows from operating activities | 159,908 | 41,296 | |||||
Cash Flows From Investing Activities: | |||||||
Additions to utility and non-utility plant | (153,512 | ) | (156,796 | ) | |||
Proceeds from sales of investments held by NDT | 76,106 | 45,787 | |||||
Purchases of investments held by NDT | (77,868 | ) | (47,313 | ) | |||
Return of principal on PVNGS lessor notes | 10,965 | 12,632 | |||||
Other, net | 1,240 | 3,687 | |||||
Net cash flows from investing activities | (143,069 | ) | (142,003 | ) |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Cash Flows From Financing Activities: | |||||||
Short-term borrowings (repayments), net | 1,300 | 124,300 | |||||
Long-term borrowings | 75,000 | — | |||||
Repayment of long-term debt | (9,445 | ) | — | ||||
Cash paid in debt exchange | (13,048 | ) | — | ||||
Proceeds from stock option exercise | 11,345 | 5,410 | |||||
Awards of common stock | (19,741 | ) | (12,674 | ) | |||
Dividends paid | (24,958 | ) | (21,770 | ) | |||
Valencia’s transactions with its owner | (8,675 | ) | (7,449 | ) | |||
Other, net | (2,804 | ) | 983 | ||||
Net cash flows from financing activities | 8,974 | 88,800 | |||||
Change in Cash and Cash Equivalents | 25,813 | (11,907 | ) | ||||
Cash and Cash Equivalents at Beginning of Period | 8,985 | 15,091 | |||||
Cash and Cash Equivalents at End of Period | $ | 34,798 | $ | 3,184 | |||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | 58,267 | $ | 56,217 | |||
Income taxes paid (refunded), net | $ | (95,472 | ) | $ | 5,302 | ||
Supplemental schedule of noncash financing activities: | |||||||
Premium on long-term debt incurred in connection with debt exchange | $ | 23,249 |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 34,798 | $ | 8,985 | |||
Accounts receivable, net of allowance for uncollectible accounts of $1,339 and $1,751 | 94,948 | 87,093 | |||||
Unbilled revenues | 71,410 | 57,266 | |||||
Other receivables | 39,651 | 53,332 | |||||
Materials, supplies, and fuel stock | 59,801 | 59,643 | |||||
Regulatory assets | 41,961 | 39,120 | |||||
Commodity derivative instruments | 2,870 | 3,785 | |||||
Income taxes receivable | 5,498 | 101,477 | |||||
Other current assets | 42,220 | 31,490 | |||||
Total current assets | 393,157 | 442,191 | |||||
Other Property and Investments: | |||||||
Investment in PVNGS lessor notes | 43,410 | 54,325 | |||||
Investments held by NDT | 197,072 | 188,971 | |||||
Other investments | 7,426 | 9,139 | |||||
Non-utility property, net of accumulated depreciation of $139 and $131 | 4,479 | 4,487 | |||||
Total other property and investments | 252,387 | 256,922 | |||||
Utility Plant: | |||||||
Plant in service and plant held for future use | 5,385,946 | 5,313,796 | |||||
Less accumulated depreciation and amortization | 1,820,441 | 1,774,223 | |||||
3,565,505 | 3,539,573 | ||||||
Construction work in progress | 160,155 | 125,287 | |||||
Nuclear fuel, net of accumulated amortization of $45,793 and $42,644 | 81,785 | 81,627 | |||||
Net utility plant | 3,807,445 | 3,746,487 | |||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | 576,758 | 555,577 | |||||
Goodwill | 278,297 | 278,297 | |||||
Commodity derivative instruments | 202 | 352 | |||||
Other deferred charges | 95,660 | 92,757 | |||||
Total deferred charges and other assets | 950,917 | 926,983 | |||||
$ | 5,403,906 | $ | 5,372,583 |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | 160,000 | $ | 158,700 | |||
Current installments of long-term debt | 52,530 | 2,530 | |||||
Accounts payable | 88,378 | 99,177 | |||||
Customer deposits | 15,153 | 18,176 | |||||
Accrued interest and taxes | 49,408 | 52,003 | |||||
Regulatory liabilities | 464 | 15,173 | |||||
Commodity derivative instruments | 1,621 | 1,000 | |||||
Dividends declared | 132 | 11,679 | |||||
Current portion of accumulated deferred income taxes | 258 | 258 | |||||
Other current liabilities | 76,646 | 75,407 | |||||
Total current liabilities | 444,590 | 434,103 | |||||
Long-term Debt | 1,711,153 | 1,669,760 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | 709,186 | 701,545 | |||||
Accumulated deferred investment tax credits | 13,146 | 14,242 | |||||
Regulatory liabilities | 452,101 | 423,460 | |||||
Asset retirement obligations | 89,395 | 85,893 | |||||
Accrued pension liability and postretirement benefit cost | 152,193 | 224,565 | |||||
Commodity derivative instruments | 1,540 | 1,933 | |||||
Other deferred credits | 109,399 | 116,523 | |||||
Total deferred credits and other liabilities | 1,526,960 | 1,568,161 | |||||
Total liabilities | 3,682,703 | 3,672,024 | |||||
Commitments and Contingencies (See Note 9) | |||||||
Cumulative Preferred Stock of Subsidiary | |||||||
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares) | 11,529 | 11,529 | |||||
Equity: | |||||||
PNMR common stockholders’ equity: | |||||||
Common stock outstanding (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares) | 1,177,163 | 1,182,819 | |||||
Accumulated other comprehensive income (loss), net of income taxes | (78,594 | ) | (81,630 | ) | |||
Retained earnings | 532,160 | 506,998 | |||||
Total PNMR common stockholders’ equity | 1,630,729 | 1,608,187 | |||||
Non-controlling interest in Valencia | 78,945 | 80,843 | |||||
Total equity | 1,709,674 | 1,689,030 | |||||
$ | 5,403,906 | $ | 5,372,583 | ||||
Attributable to PNMR | Non- controlling Interest in Valencia | ||||||||||||||||||||||
Common Stock | AOCI | Retained Earnings | Total PNMR Common Stockholder's Equity | Total Equity | |||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Balance at December 31, 2012 | $ | 1,182,819 | $ | (81,630 | ) | $ | 506,998 | $ | 1,608,187 | $ | 80,843 | $ | 1,689,030 | ||||||||||
Proceeds from stock option exercise | 11,345 | — | — | 11,345 | — | 11,345 | |||||||||||||||||
Awards of common stock | (19,741 | ) | — | — | (19,741 | ) | — | (19,741 | ) | ||||||||||||||
Excess tax (shortfall) from stock-based payment arrangements | (458 | ) | — | — | (458 | ) | — | (458 | ) | ||||||||||||||
Stock based compensation expense | 3,198 | — | — | 3,198 | — | 3,198 | |||||||||||||||||
Valencia’s transactions with its owner | — | — | — | — | (8,675 | ) | (8,675 | ) | |||||||||||||||
Net earnings before subsidiary preferred stock dividends | — | — | 38,568 | 38,568 | 6,777 | 45,345 | |||||||||||||||||
Subsidiary preferred stock dividends | — | — | (264 | ) | (264 | ) | — | (264 | ) | ||||||||||||||
Total other comprehensive income | — | 3,036 | — | 3,036 | — | 3,036 | |||||||||||||||||
Dividends declared on common stock | — | — | (13,142 | ) | (13,142 | ) | — | (13,142 | ) | ||||||||||||||
Balance at June 30, 2013 | $ | 1,177,163 | $ | (78,594 | ) | $ | 532,160 | $ | 1,630,729 | $ | 78,945 | $ | 1,709,674 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Electric Operating Revenues | $ | 279,690 | $ | 260,094 | $ | 537,583 | $ | 510,510 | |||||||
Operating Expenses: | |||||||||||||||
Cost of energy | 91,855 | 83,235 | 183,514 | 163,792 | |||||||||||
Administrative and general | 36,622 | 40,657 | 75,381 | 79,706 | |||||||||||
Energy production costs | 46,836 | 46,053 | 90,402 | 91,182 | |||||||||||
Depreciation and amortization | 26,051 | 23,946 | 51,884 | 47,580 | |||||||||||
Transmission and distribution costs | 11,133 | 11,664 | 21,735 | 22,507 | |||||||||||
Taxes other than income taxes | 8,891 | 7,870 | 19,125 | 16,969 | |||||||||||
Total operating expenses | 221,388 | 213,425 | 442,041 | 421,736 | |||||||||||
Operating income | 58,302 | 46,669 | 95,542 | 88,774 | |||||||||||
Other Income and Deductions: | |||||||||||||||
Interest income | 2,868 | 3,429 | 5,541 | 6,764 | |||||||||||
Gains (losses) on investments held by NDT | 3,272 | (795 | ) | 4,805 | 3,660 | ||||||||||
Other income | 1,559 | 1,370 | 2,872 | 3,203 | |||||||||||
Other (deductions) | (1,471 | ) | (1,564 | ) | (2,911 | ) | (2,868 | ) | |||||||
Net other income (deductions) | 6,228 | 2,440 | 10,307 | 10,759 | |||||||||||
Interest Charges | 19,890 | 18,928 | 39,847 | 37,422 | |||||||||||
Earnings before Income Taxes | 44,640 | 30,181 | 66,002 | 62,111 | |||||||||||
Income Taxes | 14,943 | 9,841 | 21,532 | 20,694 | |||||||||||
Net Earnings | 29,697 | 20,340 | 44,470 | 41,417 | |||||||||||
(Earnings) Attributable to Valencia Non-controlling Interest | (3,573 | ) | (3,455 | ) | (6,777 | ) | (6,720 | ) | |||||||
Net Earnings Attributable to PNM | 26,124 | 16,885 | 37,693 | 34,697 | |||||||||||
Preferred Stock Dividends Requirements | (132 | ) | (132 | ) | (264 | ) | (264 | ) | |||||||
Net Earnings Available for PNM Common Stock | $ | 25,992 | $ | 16,753 | $ | 37,429 | $ | 34,433 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Net Earnings | $ | 29,697 | $ | 20,340 | $ | 44,470 | $ | 41,417 | |||||||
Other Comprehensive Income: | |||||||||||||||
Unrealized Gain on Investment Securities: | |||||||||||||||
Unrealized holding gains arising during the period, net of income tax (expense) of $(290), $(3,022), $(3,401) and $(10,437) | 443 | 4,611 | 5,190 | 15,924 | |||||||||||
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $2,185, $4,992, $2,714 and $8,538 | (3,333 | ) | (7,617 | ) | (4,140 | ) | (13,028 | ) | |||||||
Pension Liability Adjustment: | |||||||||||||||
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(631), $(476), $(1,262) and $(952) | 960 | 727 | 1,920 | 1,454 | |||||||||||
Total Other Comprehensive Income (Loss) | (1,930 | ) | (2,279 | ) | 2,970 | 4,350 | |||||||||
Comprehensive Income | 27,767 | 18,061 | 47,440 | 45,767 | |||||||||||
Comprehensive (Income) Attributable to Valencia Non-controlling Interest | (3,573 | ) | (3,455 | ) | (6,777 | ) | (6,720 | ) | |||||||
Comprehensive Income Attributable to PNM | $ | 24,194 | $ | 14,606 | $ | 40,663 | $ | 39,047 |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings | $ | 44,470 | $ | 41,417 | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | 69,179 | 63,303 | |||||
Deferred income tax expense | 21,836 | 21,067 | |||||
Net unrealized (gains) losses on derivatives | 1,729 | 1,978 | |||||
Realized (gains) on investments held by NDT | (4,805 | ) | (3,660 | ) | |||
Other, net | (818 | ) | (545 | ) | |||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | (15,841 | ) | (17,867 | ) | |||
Materials, supplies, and fuel stock | (238 | ) | (5,152 | ) | |||
Other current assets | 4,299 | (10,885 | ) | ||||
Other assets | 6,196 | (5,868 | ) | ||||
Accounts payable | (5,829 | ) | (7,112 | ) | |||
Accrued interest and taxes | 45,380 | 61,503 | |||||
Other current liabilities | (23,523 | ) | 10,095 | ||||
Proceeds from governmental grants | — | 21,567 | |||||
Other liabilities | (69,059 | ) | (78,105 | ) | |||
Net cash flows from operating activities | 72,976 | 91,736 | |||||
Cash Flows From Investing Activities: | |||||||
Utility plant additions | (98,673 | ) | (111,344 | ) | |||
Proceeds from sales of NDT investments | 76,106 | 45,787 | |||||
Purchases of NDT investments | (77,868 | ) | (47,313 | ) | |||
Return of principal on PVNGS lessor notes | 10,965 | 12,632 | |||||
Other, net | 1,213 | 1,372 | |||||
Net cash flows from investing activities | (88,257 | ) | (98,866 | ) |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Cash Flows From Financing Activities: | |||||||
Short-term borrowings (repayments), net | (21,100 | ) | 20,400 | ||||
Long-term borrowings | 75,000 | — | |||||
Valencia’s transactions with its owner | (8,675 | ) | (7,449 | ) | |||
Dividends paid | (264 | ) | (17,944 | ) | |||
Other, net | (1,169 | ) | 984 | ||||
Net cash flows from financing activities | 43,792 | (4,009 | ) | ||||
Change in Cash and Cash Equivalents | 28,511 | (11,139 | ) | ||||
Cash and Cash Equivalents at Beginning of Period | 3,958 | 12,307 | |||||
Cash and Cash Equivalents at End of Period | $ | 32,469 | $ | 1,168 | |||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | 37,845 | $ | 36,286 | |||
Income taxes paid (refunded), net | $ | (44,999 | ) | $ | (63,114 | ) |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 32,469 | $ | 3,958 | |||
Accounts receivable, net of allowance for uncollectible accounts of $1,339 and $1,751 | 71,483 | 69,876 | |||||
Unbilled revenues | 62,298 | 49,085 | |||||
Other receivables | 38,529 | 50,975 | |||||
Affiliate receivables | 10,351 | 9,050 | |||||
Materials, supplies, and fuel stock | 57,027 | 56,790 | |||||
Regulatory assets | 35,559 | 36,490 | |||||
Commodity derivative instruments | 2,870 | 3,785 | |||||
Income taxes receivable | 35,528 | 80,223 | |||||
Other current assets | 37,991 | 27,457 | |||||
Total current assets | 384,105 | 387,689 | |||||
Other Property and Investments: | |||||||
Investment in PVNGS lessor notes | 43,410 | 54,325 | |||||
Investments held by NDT | 197,072 | 188,971 | |||||
Other investments | 4,170 | 4,034 | |||||
Non-utility property | 976 | 976 | |||||
Total other property and investments | 245,628 | 248,306 | |||||
Utility Plant: | |||||||
Plant in service and plant held for future use | 4,182,309 | 4,133,532 | |||||
Less accumulated depreciation and amortization | 1,395,722 | 1,355,240 | |||||
2,786,587 | 2,778,292 | ||||||
Construction work in progress | 128,507 | 102,329 | |||||
Nuclear fuel, net of accumulated amortization of $45,793 and $42,644 | 81,785 | 81,627 | |||||
Net utility plant | 2,996,879 | 2,962,248 | |||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | 422,124 | 431,956 | |||||
Goodwill | 51,632 | 51,632 | |||||
Commodity derivative instruments | 202 | 352 | |||||
Other deferred charges | 84,619 | 81,724 | |||||
Total deferred charges and other assets | 558,577 | 565,664 | |||||
$ | 4,185,189 | $ | 4,163,907 | ||||
June 30, 2013 | December 31, 2012 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | — | $ | 21,100 | |||
Accounts payable | 68,902 | 73,914 | |||||
Affiliate payables | 18,159 | 25,340 | |||||
Customer deposits | 15,153 | 18,176 | |||||
Accrued interest and taxes | 31,544 | 30,320 | |||||
Regulatory liabilities | 464 | 15,172 | |||||
Commodity derivative instruments | 1,621 | 1,000 | |||||
Dividends declared | 132 | 132 | |||||
Current portion of accumulated deferred income taxes | 3,447 | 3,447 | |||||
Other current liabilities | 56,817 | 54,150 | |||||
Total current liabilities | 196,239 | 242,751 | |||||
Long-term Debt | 1,290,598 | 1,215,579 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | 575,730 | 573,881 | |||||
Accumulated deferred investment tax credits | 13,146 | 14,242 | |||||
Regulatory liabilities | 405,972 | 379,841 | |||||
Asset retirement obligations | 88,508 | 85,042 | |||||
Accrued pension liability and postretirement benefit cost | 138,478 | 208,618 | |||||
Commodity derivative instruments | 1,540 | 1,933 | |||||
Other deferred credits | 90,042 | 95,585 | |||||
Total deferred credits and liabilities | 1,313,416 | 1,359,142 | |||||
Total liabilities | 2,800,253 | 2,817,472 | |||||
Commitments and Contingencies (See Note 9) | |||||||
Cumulative Preferred Stock | |||||||
without mandatory redemption requirements ($100 stated value; 10,000,000 authorized; issued and outstanding 115,293 shares) | 11,529 | 11,529 | |||||
Equity: | |||||||
PNM common stockholder’s equity: | |||||||
Common stock outstanding (no par value; 40,000,000 shares authorized; issued and outstanding 39,117,799 shares) | 1,061,776 | 1,061,776 | |||||
Accumulated other comprehensive income (loss), net of income taxes | (78,444 | ) | (81,414 | ) | |||
Retained earnings | 311,130 | 273,701 | |||||
Total PNM common stockholder’s equity | 1,294,462 | 1,254,063 | |||||
Non-controlling interest in Valencia | 78,945 | 80,843 | |||||
Total equity | 1,373,407 | 1,334,906 | |||||
$ | 4,185,189 | $ | 4,163,907 |
Attributable to PNM | |||||||||||||||||||||||
Total PNM Common Stockholder’s Equity | Non- controlling Interest in Valencia | ||||||||||||||||||||||
Common Stock | AOCI | Retained Earnings | Total Equity | ||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Balance at December 31, 2012 | $ | 1,061,776 | $ | (81,414 | ) | $ | 273,701 | $ | 1,254,063 | $ | 80,843 | $ | 1,334,906 | ||||||||||
Valencia’s transactions with its owner | — | — | — | — | (8,675 | ) | (8,675 | ) | |||||||||||||||
Net earnings | — | — | 37,693 | 37,693 | 6,777 | 44,470 | |||||||||||||||||
Total other comprehensive income | — | 2,970 | — | 2,970 | — | 2,970 | |||||||||||||||||
Dividends declared on preferred stock | — | — | (264 | ) | (264 | ) | — | (264 | ) | ||||||||||||||
Balance at June 30, 2013 | $ | 1,061,776 | $ | (78,444 | ) | $ | 311,130 | $ | 1,294,462 | $ | 78,945 | $ | 1,373,407 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Electric Operating Revenues | $ | 67,909 | $ | 63,766 | $ | 127,680 | $ | 118,724 | |||||||
Operating Expenses: | |||||||||||||||
Cost of energy | 13,804 | 11,484 | 26,851 | 22,773 | |||||||||||
Administrative and general | 10,686 | 10,103 | 21,804 | 20,570 | |||||||||||
Depreciation and amortization | 12,279 | 12,066 | 23,960 | 23,353 | |||||||||||
Transmission and distribution costs | 6,016 | 5,901 | 11,708 | 11,307 | |||||||||||
Taxes other than income taxes | 5,457 | 5,315 | 10,636 | 10,031 | |||||||||||
Total operating expenses | 48,242 | 44,869 | 94,959 | 88,034 | |||||||||||
Operating income | 19,667 | 18,897 | 32,721 | 30,690 | |||||||||||
Other Income and Deductions: | |||||||||||||||
Other income | 609 | 448 | 946 | 937 | |||||||||||
Other (deductions) | (123 | ) | 326 | (252 | ) | (59 | ) | ||||||||
Net other income (deductions) | 486 | 774 | 694 | 878 | |||||||||||
Interest Charges | 6,759 | 7,069 | 14,005 | 14,167 | |||||||||||
Earnings before Income Taxes | 13,394 | 12,602 | 19,410 | 17,401 | |||||||||||
Income Taxes | 5,055 | 4,584 | 7,345 | 6,372 | |||||||||||
Net Earnings | $ | 8,339 | $ | 8,018 | $ | 12,065 | $ | 11,029 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Net Earnings | $ | 8,339 | $ | 8,018 | $ | 12,065 | $ | 11,029 | |||||||
Other Comprehensive Income (Loss): | |||||||||||||||
Fair Value Adjustment for Cash Flow Hedges: | |||||||||||||||
Change in fair market value, net of income tax (expense) benefit of $3, $40, $(1) and $99 | (6 | ) | (72 | ) | 2 | (178 | ) | ||||||||
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(18), $(16), $(35) and $(31) | 33 | 29 | 64 | 56 | |||||||||||
Total Other Comprehensive Income (Loss) | 27 | (43 | ) | 66 | (122 | ) | |||||||||
Comprehensive Income | $ | 8,366 | $ | 7,975 | $ | 12,131 | $ | 10,907 |
Six Months Ended June 30, | |||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Cash Flows From Operating Activities: | |||||||
Net earnings | $ | 12,065 | $ | 11,029 | |||
Adjustments to reconcile net earnings to net cash flows from operating activities: | |||||||
Depreciation and amortization | 26,034 | 25,885 | |||||
Deferred income tax expense | 4,348 | 6,247 | |||||
Other, net | (10 | ) | (258 | ) | |||
Changes in certain assets and liabilities: | |||||||
Accounts receivable and unbilled revenues | (7,180 | ) | (3,034 | ) | |||
Materials and supplies | 79 | (98 | ) | ||||
Other current assets | (4,082 | ) | (3,904 | ) | |||
Other assets | 590 | (1,066 | ) | ||||
Accounts payable | 807 | 2,987 | |||||
Accrued interest and taxes | (1,517 | ) | (4,755 | ) | |||
Other current liabilities | 1,278 | 4,214 | |||||
Other liabilities | 886 | (3,408 | ) | ||||
Net cash flows from operating activities | 33,298 | 33,839 | |||||
Cash Flows From Investing Activities: | |||||||
Utility plant additions | (47,390 | ) | (39,595 | ) | |||
Proceeds from sales of utility plant | — | 1,367 | |||||
Net cash flows from investing activities | (47,390 | ) | (38,228 | ) | |||
Cash Flow From Financing Activities: | |||||||
Short-term borrowings (repayments), net | 25,000 | — | |||||
Short-term borrowings (repayments) – affiliate, net | 7,500 | 7,400 | |||||
Cash paid in debt exchange | (13,048 | ) | — | ||||
Dividends paid | (3,726 | ) | (3,010 | ) | |||
Other, net | (1,634 | ) | (1 | ) | |||
Net cash flows from financing activities | 14,092 | 4,389 | |||||
Change in Cash and Cash Equivalents | — | — | |||||
Cash and Cash Equivalents at Beginning of Period | 1 | 1 | |||||
Cash and Cash Equivalents at End of Period | $ | 1 | $ | 1 | |||
Supplemental Cash Flow Disclosures: | |||||||
Interest paid, net of amounts capitalized | $ | 13,267 | $ | 12,761 | |||
Income taxes paid, net | $ | 696 | $ | 1,848 | |||
Supplemental schedule of noncash financing activities: | |||||||
Premium on long-term debt incurred in connection with debt exchange | $ | 23,249 |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 1 | $ | 1 | |||
Accounts receivable | 23,465 | 17,217 | |||||
Unbilled revenues | 9,112 | 8,181 | |||||
Other receivables | 614 | 2,359 | |||||
Materials and supplies | 2,774 | 2,853 | |||||
Regulatory assets | 6,402 | 2,630 | |||||
Current portion of accumulated deferred income taxes | 1,131 | 1,131 | |||||
Other current assets | 2,037 | 1,107 | |||||
Total current assets | 45,536 | 35,479 | |||||
Other Property and Investments: | |||||||
Other investments | 281 | 281 | |||||
Non-utility property | 2,240 | 2,240 | |||||
Total other property and investments | 2,521 | 2,521 | |||||
Utility Plant: | |||||||
Plant in service and plant held for future use | 1,033,729 | 1,009,108 | |||||
Less accumulated depreciation and amortization | 340,091 | 339,315 | |||||
693,638 | 669,793 | ||||||
Construction work in progress | 24,658 | 19,801 | |||||
Net utility plant | 718,296 | 689,594 | |||||
Deferred Charges and Other Assets: | |||||||
Regulatory assets | 154,634 | 123,621 | |||||
Goodwill | 226,665 | 226,665 | |||||
Other deferred charges | 8,276 | 8,349 | |||||
Total deferred charges and other assets | 389,575 | 358,635 | |||||
$ | 1,155,928 | $ | 1,086,229 |
June 30, 2013 | December 31, 2012 | ||||||
(In thousands, except share information) | |||||||
LIABILITIES AND STOCKHOLDER’S EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | 25,000 | $ | — | |||
Short-term debt – affiliate | 35,800 | 28,300 | |||||
Current installments of long-term debt | 50,000 | — | |||||
Accounts payable | 8,769 | 8,848 | |||||
Affiliate payables | 3,435 | 4,381 | |||||
Accrued interest and taxes | 28,974 | 30,491 | |||||
Other current liabilities | 10,882 | 8,854 | |||||
Total current liabilities | 162,860 | 80,874 | |||||
Long-term Debt | 286,238 | 311,589 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes | 168,200 | 163,710 | |||||
Regulatory liabilities | 45,693 | 43,619 | |||||
Asset retirement obligations | 763 | 732 | |||||
Accrued pension liability and postretirement benefit cost | 13,715 | 15,947 | |||||
Other deferred credits | 6,240 | 5,944 | |||||
Total deferred credits and other liabilities | 234,611 | 229,952 | |||||
Total liabilities | 683,709 | 622,415 | |||||
Commitments and Contingencies (See Note 9) | |||||||
Common Stockholder’s Equity: | |||||||
Common stock outstanding ($10 par value; 12,000,000 shares authorized; | |||||||
issued and outstanding 6,358 shares) | 64 | 64 | |||||
Paid-in-capital | 390,366 | 390,366 | |||||
Accumulated other comprehensive income (loss), net of income taxes | (150 | ) | (216 | ) | |||
Retained earnings | 81,939 | 73,600 | |||||
Total common stockholder’s equity | 472,219 | 463,814 | |||||
$ | 1,155,928 | $ | 1,086,229 |
Common Stock | Paid-in Capital | AOCI | Retained Earnings | Total Common Stockholder's Equity | |||||||||||||||
(In thousands) | |||||||||||||||||||
Balance at December 31, 2012 | $ | 64 | $ | 390,366 | $ | (216 | ) | $ | 73,600 | $ | 463,814 | ||||||||
Net earnings | — | — | — | 12,065 | 12,065 | ||||||||||||||
Total other comprehensive income | — | — | 66 | — | 66 | ||||||||||||||
Dividends declared on common stock | — | — | — | (3,726 | ) | (3,726 | ) | ||||||||||||
Balance at June 30, 2013 | $ | 64 | $ | 390,366 | $ | (150 | ) | $ | 81,939 | $ | 472,219 |
(1) | Significant Accounting Policies and Responsibility for Financial Statements |
(2) | Segment Information |
PNM | TNMP | Corporate and Other | Consolidated | ||||||||||||
Three Months Ended June 30, 2013 | (In thousands) | ||||||||||||||
Electric operating revenues | $ | 279,690 | $ | 67,909 | $ | — | $ | 347,599 | |||||||
Cost of energy | 91,855 | 13,804 | — | 105,659 | |||||||||||
Margin | 187,835 | 54,105 | — | 241,940 | |||||||||||
Other operating expenses | 103,482 | 22,159 | (3,207 | ) | 122,434 | ||||||||||
Depreciation and amortization | 26,051 | 12,279 | 3,309 | 41,639 | |||||||||||
Operating income (loss) | 58,302 | 19,667 | (102 | ) | 77,867 | ||||||||||
Interest income | 2,868 | — | (35 | ) | 2,833 | ||||||||||
Other income (deductions) | 3,360 | 486 | (2,213 | ) | 1,633 | ||||||||||
Net interest charges | (19,890 | ) | (6,759 | ) | (3,967 | ) | (30,616 | ) | |||||||
Segment earnings (loss) before income taxes | 44,640 | 13,394 | (6,317 | ) | 51,717 | ||||||||||
Income taxes | 14,943 | 5,055 | 336 | 20,334 | |||||||||||
Segment earnings (loss) | 29,697 | 8,339 | (6,653 | ) | 31,383 | ||||||||||
Valencia non-controlling interest | (3,573 | ) | — | — | (3,573 | ) | |||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | |||||||||
Segment earnings (loss) attributable to PNMR | $ | 25,992 | $ | 8,339 | $ | (6,653 | ) | $ | 27,678 | ||||||
Six Months Ended June 30, 2013 | |||||||||||||||
Electric operating revenues | $ | 537,583 | $ | 127,680 | $ | — | $ | 665,263 | |||||||
Cost of energy | 183,514 | 26,851 | — | 210,365 | |||||||||||
Margin | 354,069 | 100,829 | — | 454,898 | |||||||||||
Other operating expenses | 206,643 | 44,148 | (6,910 | ) | 243,881 | ||||||||||
Depreciation and amortization | 51,884 | 23,960 | 6,602 | 82,446 | |||||||||||
Operating income | 95,542 | 32,721 | 308 | 128,571 | |||||||||||
Interest income | 5,541 | — | (74 | ) | 5,467 | ||||||||||
Other income (deductions) | 4,766 | 694 | (3,936 | ) | 1,524 | ||||||||||
Net interest charges | (39,847 | ) | (14,005 | ) | (8,062 | ) | (61,914 | ) | |||||||
Segment earnings (loss) before income taxes | 66,002 | 19,410 | (11,764 | ) | 73,648 | ||||||||||
Income taxes (benefit) | 21,532 | 7,345 | (574 | ) | 28,303 | ||||||||||
Segment earnings (loss) | 44,470 | 12,065 | (11,190 | ) | 45,345 | ||||||||||
Valencia non-controlling interest | (6,777 | ) | — | — | (6,777 | ) | |||||||||
Subsidiary preferred stock dividends | (264 | ) | — | — | (264 | ) | |||||||||
Segment earnings (loss) attributable to PNMR | $ | 37,429 | $ | 12,065 | $ | (11,190 | ) | $ | 38,304 | ||||||
At June 30, 2013: | |||||||||||||||
Total Assets | $ | 4,185,189 | $ | 1,155,928 | $ | 62,789 | $ | 5,403,906 | |||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | |||||||
Additions to utility and non-utility plant included in accounts payable | $ | 7,900 | $ | 1,101 | $ | 749 | $ | 9,750 |
PNM | TNMP | Corporate and Other | Consolidated | ||||||||||||
Three Months Ended June 30, 2012 | (In thousands) | ||||||||||||||
Electric operating revenues | $ | 260,094 | $ | 63,766 | $ | — | $ | 323,860 | |||||||
Cost of energy | 83,235 | 11,484 | — | 94,719 | |||||||||||
Margin | 176,859 | 52,282 | — | 229,141 | |||||||||||
Other operating expenses | 106,244 | 21,319 | (4,582 | ) | 122,981 | ||||||||||
Depreciation and amortization | 23,946 | 12,066 | 5,042 | 41,054 | |||||||||||
Operating income (loss) | 46,669 | 18,897 | (460 | ) | 65,106 | ||||||||||
Interest income | 3,429 | — | (43 | ) | 3,386 | ||||||||||
Other income (deductions) | (989 | ) | 774 | (1,434 | ) | (1,649 | ) | ||||||||
Net interest charges | (18,928 | ) | (7,069 | ) | (4,201 | ) | (30,198 | ) | |||||||
Segment earnings (loss) before income taxes | 30,181 | 12,602 | (6,138 | ) | 36,645 | ||||||||||
Income taxes (benefit) | 9,841 | 4,584 | (2,879 | ) | 11,546 | ||||||||||
Segment earnings (loss) | 20,340 | 8,018 | (3,259 | ) | 25,099 | ||||||||||
Valencia non-controlling interest | (3,455 | ) | — | — | (3,455 | ) | |||||||||
Subsidiary preferred stock dividends | (132 | ) | — | — | (132 | ) | |||||||||
Segment earnings (loss) attributable to PNMR | $ | 16,753 | $ | 8,018 | $ | (3,259 | ) | $ | 21,512 | ||||||
Six Months Ended June 30, 2012 | |||||||||||||||
Electric operating revenues | $ | 510,510 | $ | 118,724 | $ | — | $ | 629,234 | |||||||
Cost of energy | 163,792 | 22,773 | — | 186,565 | |||||||||||
Margin | 346,718 | 95,951 | — | 442,669 | |||||||||||
Other operating expenses | 210,364 | 41,908 | (7,906 | ) | 244,366 | ||||||||||
Depreciation and amortization | 47,580 | 23,353 | 8,535 | 79,468 | |||||||||||
Operating income (loss) | 88,774 | 30,690 | (629 | ) | 118,835 | ||||||||||
Interest income | 6,764 | — | (86 | ) | 6,678 | ||||||||||
Other income (deductions) | 3,995 | 878 | (3,974 | ) | 899 | ||||||||||
Net interest charges | (37,422 | ) | (14,167 | ) | (8,176 | ) | (59,765 | ) | |||||||
Segment earnings (loss) before income taxes | 62,111 | 17,401 | (12,865 | ) | 66,647 | ||||||||||
Income taxes (benefit) | 20,694 | 6,372 | (5,995 | ) | 21,071 | ||||||||||
Segment earnings (loss) | 41,417 | 11,029 | (6,870 | ) | 45,576 | ||||||||||
Valencia non-controlling interest | (6,720 | ) | — | — | (6,720 | ) | |||||||||
Subsidiary preferred stock dividends | (264 | ) | — | — | (264 | ) | |||||||||
Segment earnings (loss) attributable to PNMR | $ | 34,433 | $ | 11,029 | $ | (6,870 | ) | $ | 38,592 | ||||||
At June 30, 2012: | |||||||||||||||
Total Assets | $ | 4,069,375 | $ | 1,054,679 | $ | 128,535 | $ | 5,252,589 | |||||||
Goodwill | $ | 51,632 | $ | 226,665 | $ | — | $ | 278,297 | |||||||
Additions to utility and non-utility plant included in accounts payable | $ | 8,681 | $ | 551 | $ | 392 | $ | 9,624 |
(3) | Variable Interest Entities |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Operating revenues | $ | 4,922 | $ | 4,888 | $ | 9,697 | $ | 9,559 | |||||||
Operating expenses | (1,349 | ) | (1,433 | ) | (2,920 | ) | (2,839 | ) | |||||||
Earnings attributable to non-controlling interest | $ | 3,573 | $ | 3,455 | $ | 6,777 | $ | 6,720 |
June 30, | December 31, | ||||||
2013 | 2012 | ||||||
(In thousands) | |||||||
Current assets | $ | 3,124 | $ | 3,655 | |||
Net property, plant, and equipment | 76,541 | 77,953 | |||||
Total assets | 79,665 | 81,608 | |||||
Current liabilities | 720 | 765 | |||||
Owners’ equity – non-controlling interest | $ | 78,945 | $ | 80,843 |
(4) | Fair Value of Derivative and Other Financial Instruments |
Economic Hedges | |||||||
June 30, 2013 | December 31, 2012 | ||||||
PNMR and PNM | (In thousands) | ||||||
Current assets | $ | 2,870 | $ | 3,785 | |||
Deferred charges | 202 | 352 | |||||
3,072 | 4,137 | ||||||
Current liabilities | (1,621 | ) | (1,000 | ) | |||
Long-term liabilities | (1,540 | ) | (1,933 | ) | |||
(3,161 | ) | (2,933 | ) | ||||
Net | $ | (89 | ) | $ | 1,204 |
Economic Hedges | |||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
PNMR and PNM | (In thousands) | ||||||||||||||
Electric operating revenues | $ | 3,269 | $ | (3,581 | ) | $ | (1,334 | ) | $ | 1,637 | |||||
Cost of energy | (263 | ) | 63 | 493 | (541 | ) | |||||||||
Total gain (loss) | $ | 3,006 | $ | (3,518 | ) | $ | (841 | ) | $ | 1,096 |
Economic Hedges | |||||
MMBTU | MWh | ||||
June 30, 2013 | |||||
PNMR and PNM | 1,675,000 | (1,798,394 | ) | ||
December 31, 2012 | |||||
PNMR and PNM | 1,127,500 | (2,477,520 | ) |
Contingent Feature – Credit Rating Downgrade | Contractual Liability | Existing Cash Collateral | Net Exposure | |||||||||
(In thousands) | ||||||||||||
June 30, 2013 | ||||||||||||
PNMR and PNM | $ | 2,675 | $ | — | $ | 2,581 | ||||||
December 31, 2012 | ||||||||||||
PNMR and PNM | $ | 2,933 | $ | — | $ | 2,777 |
June 30, 2013 | December 31, 2012 | ||||||||||||||
Unrealized Gains | Fair Value | Unrealized Gains | Fair Value | ||||||||||||
(In thousands) | |||||||||||||||
Cash and cash equivalents | $ | — | $ | 26,652 | $ | — | $ | 4,628 | |||||||
Equity securities: | |||||||||||||||
Domestic value | 9,205 | 33,675 | 5,223 | 30,044 | |||||||||||
Domestic growth | 16,846 | 59,347 | 15,212 | 51,650 | |||||||||||
International and other | 511 | 15,127 | 247 | 14,868 | |||||||||||
Fixed income securities: | |||||||||||||||
U.S. Government | 313 | 17,077 | 1,305 | 32,592 | |||||||||||
Municipals | 1,819 | 40,284 | 4,069 | 43,861 | |||||||||||
Corporate and other | 199 | 8,607 | 1,100 | 14,868 | |||||||||||
$ | 28,893 | $ | 200,769 | $ | 27,156 | $ | 192,511 |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands) | |||||||||||||||
Proceeds from sales | $ | 61,821 | $ | 19,027 | $ | 76,106 | $ | 45,787 | |||||||
Gross realized gains | $ | 4,960 | $ | 2,434 | $ | 6,351 | $ | 4,766 | |||||||
Gross realized (losses) | $ | (1,311 | ) | $ | (1,186 | ) | $ | (1,717 | ) | $ | (1,925 | ) |
Fair Value | |||||||||||
Available-for-Sale | Held-to-Maturity | ||||||||||
PNMR and PNM | PNMR | PNM | |||||||||
(In thousands) | |||||||||||
Within 1 year | $ | 1,470 | $ | 7,519 | $ | 3,819 | |||||
After 1 year through 5 years | 18,713 | 67,362 | 66,018 | ||||||||
After 5 years through 10 years | 8,334 | — | — | ||||||||
After 10 years through 15 years | 7,887 | — | — | ||||||||
After 15 years through 20 years | 10,616 | — | — | ||||||||
After 20 years | 18,948 | — | — | ||||||||
$ | 65,968 | $ | 74,881 | $ | 69,837 |
GAAP Fair Value Hierarchy | |||||||||||
Total | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | |||||||||
June 30, 2013 | (In thousands) | ||||||||||
PNMR and PNM | |||||||||||
Decommissioning and reclamation investments: | |||||||||||
Cash and cash equivalents | $ | 26,652 | $ | 26,652 | $ | — | |||||
Equity securities: | |||||||||||
Domestic value | 33,675 | 33,675 | — | ||||||||
Domestic growth | 59,347 | 59,347 | — | ||||||||
International and other | 15,127 | 15,127 | — | ||||||||
Fixed income securities: | |||||||||||
U.S. government | 17,077 | 15,312 | 1,765 | ||||||||
Municipals | 40,284 | — | 40,284 | ||||||||
Corporate and other | 8,607 | — | 8,607 | ||||||||
$ | 200,769 | $ | 150,113 | $ | 50,656 | ||||||
Commodity derivative assets | $ | 3,072 | $ | — | $ | 3,072 | |||||
Commodity derivative liabilities | (3,161 | ) | — | (3,161 | ) | ||||||
Net | $ | (89 | ) | $ | — | $ | (89 | ) | |||
December 31, 2012 | |||||||||||
PNMR and PNM | |||||||||||
Decommissioning and reclamation investments: | |||||||||||
Cash and cash equivalents | $ | 4,628 | $ | 4,628 | $ | — | |||||
Equity securities: | |||||||||||
Domestic value | 30,044 | 30,044 | — | ||||||||
Domestic growth | 51,650 | 51,650 | — | ||||||||
International and other | 14,868 | 14,868 | — | ||||||||
Fixed income securities: | |||||||||||
U.S. government | 32,592 | 27,737 | 4,855 | ||||||||
Municipals | 43,861 | — | 43,861 | ||||||||
Corporate and other | 14,868 | — | 14,868 | ||||||||
$ | 192,511 | $ | 128,927 | $ | 63,584 | ||||||
Commodity derivative assets | $ | 4,137 | $ | — | $ | 4,137 | |||||
Commodity derivative liabilities | (2,933 | ) | — | (2,933 | ) | ||||||
Net | $ | 1,204 | $ | — | $ | 1,204 |
GAAP Fair Value Hierarchy | |||||||||||||||||||
Carrying Amount | Fair Value | Level 1 | Level 2 | Level 3 | |||||||||||||||
June 30, 2013 | (In thousands) | ||||||||||||||||||
PNMR | |||||||||||||||||||
Long-term debt | $ | 1,763,683 | $ | 1,977,764 | $ | — | $ | 1,974,064 | $ | 3,700 | |||||||||
Investment in PVNGS lessor notes | $ | 66,033 | $ | 69,837 | $ | — | $ | — | $ | 69,837 | |||||||||
Other investments | $ | 3,729 | $ | 6,944 | $ | 754 | $ | — | $ | 6,190 | |||||||||
PNM | |||||||||||||||||||
Long-term debt | $ | 1,290,598 | $ | 1,417,596 | $ | — | $ | 1,417,596 | $ | — | |||||||||
Investment in PVNGS lessor notes | $ | 66,033 | $ | 69,837 | $ | — | $ | — | $ | 69,837 | |||||||||
Other investments | $ | 473 | $ | 473 | $ | 473 | $ | — | $ | — | |||||||||
TNMP | |||||||||||||||||||
Long-term debt | $ | 336,238 | $ | 395,666 | $ | — | $ | 395,666 | $ | — | |||||||||
Other investments | $ | 281 | $ | 281 | $ | 281 | $ | — | $ | — | |||||||||
December 31, 2012 | |||||||||||||||||||
PNMR | |||||||||||||||||||
Long-term debt | $ | 1,672,290 | $ | 1,969,362 | $ | — | $ | 1,966,725 | $ | 2,637 | |||||||||
Investment in PVNGS lessor notes | $ | 77,682 | $ | 84,198 | $ | — | $ | — | $ | 84,198 | |||||||||
Other investments | $ | 5,599 | $ | 6,965 | $ | 774 | $ | — | $ | 6,191 | |||||||||
PNM | |||||||||||||||||||
Long-term debt | $ | 1,215,579 | $ | 1,385,433 | $ | — | $ | 1,385,433 | $ | — | |||||||||
Investment in PVNGS lessor notes | $ | 77,682 | $ | 84,198 | $ | — | $ | — | $ | 84,198 | |||||||||
Other investments | $ | 494 | $ | 494 | $ | 494 | $ | — | $ | — | |||||||||
TNMP | |||||||||||||||||||
Long-term debt | $ | 311,589 | $ | 418,166 | $ | — | $ | 418,166 | $ | — | |||||||||
Other investments | $ | 281 | $ | 281 | $ | 281 | $ | — | $ | — |
(5) | Earnings Per Share |
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
(In thousands, except per share amounts) | |||||||||||||||
Net Earnings Attributable to PNMR | $ | 27,678 | $ | 21,512 | $ | 38,304 | $ | 38,592 | |||||||
Average Number of Common Shares: | |||||||||||||||
Outstanding during period | 79,654 | 79,654 | 79,654 | 79,654 | |||||||||||
Vested awards of restricted stock | 194 | 154 | 202 | 177 | |||||||||||
Average Shares - Basic | 79,848 | 79,808 | 79,856 | 79,831 | |||||||||||
Dilutive Effect of Common Stock Equivalents (1): | |||||||||||||||
Stock options and restricted stock | 607 | 558 | 661 | 590 | |||||||||||
Average Shares - Diluted | 80,455 | 80,366 | 80,517 | 80,421 | |||||||||||
Net Earnings Per Share of Common Stock: | |||||||||||||||
Basic | $ | 0.35 | $ | 0.27 | $ | 0.48 | $ | 0.48 | |||||||
Diluted | $ | 0.34 | $ | 0.27 | $ | 0.48 | $ | 0.48 |
(1) | Excludes the effect of out-of-the-money options for 825,877 shares of common stock at June 30, 2013. |
(6) | Stock-Based Compensation |
Six Months Ended June 30, | ||||||||
Restricted Shares and Performance Based Shares | 2013 | 2012 | ||||||
Expected quarterly dividends per share | $ | 0.165 | $ | 0.145 | ||||
Risk-free interest rate | 0.34 | % | 0.65 | % | ||||
Market-Based Shares | ||||||||
Dividend yield | 2.86 | % | 3.45 | % | ||||
Expected volatility | 25.11 | % | 43.98 | % | ||||
Risk-free interest rate | 0.36 | % | 1.04 | % |
Stock Option Shares | Weighted- Average Exercise Price | Restricted Stock | Weighted- Average Grant Date Fair Value | ||||||||||
Outstanding at beginning of period | 1,992,700 | $ | 20.72 | 353,722 | $ | 14.03 | |||||||
Granted | — | $ | — | 249,113 | $ | 20.03 | |||||||
Exercised | (225,328 | ) | $ | 13.09 | (275,122 | ) | $ | 15.93 | |||||
Forfeited | — | $ | — | (8,982 | ) | $ | 18.05 | ||||||
Expired | (258,526 | ) | $ | 27.24 | — | $ | — | ||||||
Outstanding at end of period | 1,508,846 | $ | 20.75 | 318,731 | $ | 17.87 |
Six Months Ended June 30, | ||||||||
Stock Options | 2013 | 2012 | ||||||
Weighted-average grant date fair value of options granted | $ | — | $ | — | ||||
Total fair value of options that vested (in thousands) | $ | 625 | $ | 1,058 | ||||
Total intrinsic value of options exercised (in thousands) | $ | 2,189 | $ | 1,917 | ||||
Restricted Stock | ||||||||
Weighted-average grant date fair value | $ | 20.03 | $ | 15.63 | ||||
Total fair value of restricted shares that vested (in thousands) | $ | 4,383 | $ | 3,828 |
(7) | Financing |
June 30, | December 31, | |||||||
Short-term Debt | 2013 | 2012 | ||||||
(In thousands) | ||||||||
PNM – Revolving credit facility | $ | — | $ | 21,100 | ||||
TNMP – Revolving credit facility | 25,000 | — | ||||||
PNMR: | ||||||||
Revolving credit facility | 35,000 | 37,600 | ||||||
PNMR Term Loan Agreement | 100,000 | 100,000 | ||||||
$ | 160,000 | $ | 158,700 |
(8) | Pension and Other Postretirement Benefit Plans |
Three Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic | |||||||||||||||||||||||
Benefit Cost | |||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 65 | $ | 54 | $ | — | $ | — | |||||||||||
Interest cost | 7,035 | 8,058 | 1,029 | 1,324 | 180 | 219 | |||||||||||||||||
Expected return on plan assets | (10,482 | ) | (10,325 | ) | (1,261 | ) | (1,225 | ) | — | — | |||||||||||||
Amortization of net (gain) loss | 3,710 | 2,629 | 1,061 | 972 | 58 | 21 | |||||||||||||||||
Amortization of prior service cost | 19 | 79 | (336 | ) | (336 | ) | — | — | |||||||||||||||
Net periodic benefit cost | $ | 282 | $ | 441 | $ | 558 | $ | 789 | $ | 238 | $ | 240 | |||||||||||
Six Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic | |||||||||||||||||||||||
Benefit Cost | |||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 130 | $ | 108 | $ | — | $ | — | |||||||||||
Interest cost | 14,071 | 16,116 | 2,057 | 2,648 | 360 | 438 | |||||||||||||||||
Expected return on plan assets | (20,965 | ) | (20,650 | ) | (2,522 | ) | (2,450 | ) | — | — | |||||||||||||
Amortization of net (gain) loss | 7,420 | 5,258 | 2,121 | 1,944 | 116 | 42 | |||||||||||||||||
Amortization of prior service cost | 38 | 158 | (672 | ) | (672 | ) | — | — | |||||||||||||||
Net periodic benefit cost | $ | 564 | $ | 882 | $ | 1,114 | $ | 1,578 | $ | 476 | $ | 480 |
Three Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic | |||||||||||||||||||||||
Benefit Cost (Income) | |||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 75 | $ | 61 | $ | — | $ | — | |||||||||||
Interest cost | 772 | 909 | 141 | 156 | 9 | 11 | |||||||||||||||||
Expected return on plan assets | (1,212 | ) | (1,331 | ) | (126 | ) | (129 | ) | — | — | |||||||||||||
Amortization of net (gain) loss | 262 | 115 | — | (52 | ) | — | — | ||||||||||||||||
Amortization of prior service cost | — | — | 14 | 14 | — | — | |||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (178 | ) | $ | (307 | ) | $ | 104 | $ | 50 | $ | 9 | $ | 11 | |||||||||
Six Months Ended June 30, | |||||||||||||||||||||||
Pension Plan | OPEB Plan | Executive Retirement Program | |||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
Components of Net Periodic | |||||||||||||||||||||||
Benefit Cost (Income) | |||||||||||||||||||||||
Service cost | $ | — | $ | — | $ | 150 | $ | 122 | $ | — | $ | — | |||||||||||
Interest cost | 1,544 | 1,818 | 283 | 312 | 18 | 22 | |||||||||||||||||
Expected return on plan assets | (2,425 | ) | (2,662 | ) | (252 | ) | (258 | ) | — | — | |||||||||||||
Amortization of net (gain) loss | 524 | 230 | — | (104 | ) | — | — | ||||||||||||||||
Amortization of prior service cost | — | — | 28 | 28 | — | — | |||||||||||||||||
Net Periodic Benefit Cost (Income) | $ | (357 | ) | $ | (614 | ) | $ | 209 | $ | 100 | $ | 18 | $ | 22 |
(10) | Regulatory and Rate Matters |
(11) | Accumulated Other Comprehensive Income (Loss) |
Accumulated Other Comprehensive Income (Loss) | |||||||||||||||
Unrealized | Fair Value | ||||||||||||||
Gain on | Pension | Adjustment | |||||||||||||
Investment | Liability | for Cash Flow | |||||||||||||
Securities | Adjustment | Hedges | Total | ||||||||||||
(In thousands) | |||||||||||||||
PNMR | |||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | (216 | ) | $ | (81,630 | ) | ||||
Amounts reclassified from AOCI (pre-tax) | (6,854 | ) | 3,182 | 99 | (3,573 | ) | |||||||||
Income tax impact of amounts reclassified | 2,714 | (1,262 | ) | (35 | ) | 1,417 | |||||||||
Other OCI changes (pre-tax) | 8,591 | — | 3 | 8,594 | |||||||||||
Income tax impact of other OCI changes | (3,401 | ) | — | (1 | ) | (3,402 | ) | ||||||||
Net change after income taxes | 1,050 | 1,920 | 66 | 3,036 | |||||||||||
Balance at June 30, 2013 | $ | 17,456 | $ | (95,900 | ) | $ | (150 | ) | $ | (78,594 | ) |
PNM | |||||||||||||||
Balance at December 31, 2012 | $ | 16,406 | $ | (97,820 | ) | $ | — | $ | (81,414 | ) | |||||
Amounts reclassified from AOCI (pre-tax) | (6,854 | ) | 3,182 | — | (3,672 | ) | |||||||||
Income tax impact of amounts reclassified | 2,714 | (1,262 | ) | — | 1,452 | ||||||||||
Other OCI changes (pre-tax) | 8,591 | — | — | 8,591 | |||||||||||
Income tax impact of other OCI changes | (3,401 | ) | — | — | (3,401 | ) | |||||||||
Net change after income taxes | 1,050 | 1,920 | — | 2,970 | |||||||||||
Balance at June 30, 2013 | $ | 17,456 | $ | (95,900 | ) | $ | — | $ | (78,444 | ) |
TNMP | |||||||||||||||
Balance at December 31, 2012 | $ | — | $ | — | $ | (216 | ) | $ | (216 | ) | |||||
Amounts reclassified from AOCI (pre-tax) | — | — | 99 | 99 | |||||||||||
Income tax impact of amounts reclassified | — | — | (35 | ) | (35 | ) | |||||||||
Other OCI changes (pre-tax) | — | — | 3 | 3 | |||||||||||
Income tax impact of other OCI changes | — | — | (1 | ) | (1 | ) | |||||||||
Net change after income taxes | — | — | 66 | 66 | |||||||||||
Balance at June 30, 2013 | $ | — | $ | — | $ | (150 | ) | $ | (150 | ) |
(12) | Related Party Transactions |
Three Months Ended | Six Months Ended | ||||||||||||
June 30, | June 30, | ||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||
(In thousands) | |||||||||||||
Services billings: | |||||||||||||
PNMR to PNM | $ | 20,837 | $ | 23,832 | 43,489 | 45,887 | |||||||
PNMR to TNMP | 6,856 | 6,816 | 14,217 | 13,767 | |||||||||
PNM to TNMP | 133 | 168 | 241 | 289 | |||||||||
TNMP to PNMR | 2 | 4 | 4 | 8 | |||||||||
Interest billings: | |||||||||||||
PNMR to TNMP | 119 | 32 | 215 | 50 | |||||||||
PNMR to PNM | — | 1 | 1 | 1 | |||||||||
PNM to PNMR | 37 | 44 | 78 | 89 | |||||||||
Income tax sharing payments: | |||||||||||||
PNMR to PNM | 45,000 | — | 45,000 | 63,114 | |||||||||
PNMR to TNMP | — | — | — | 1,952 |
(13) | Income Taxes |
• | Earning authorized returns on its regulated businesses |
• | Continuing to improve credit ratings |
• | Providing a top-quartile total return to investors |
• | Achieving industry-leading safety performance and customer satisfaction |
• | Maintaining strong plant performance and reliability |
• | Developing strategies to meet regional haze rules at the coal-fired SJGS as cost effectively as possible while providing broad environmental benefits |
• | PNM submitting a new BART analysis to NMED, which occurred in April 2013 |
• | NMED submitting a revised SIP to EIB, which occurred in May 2013 |
• | Approval of the revised SIP by EIB |
• | EPA approval of the revised SIP |
• | NMPRC approval of the retirement of Units 2 and 3, as well as recovery of the unrecovered investment and costs to retire those units, and plans to acquire replacement power |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
(In millions, except per share amounts) | |||||||||||||||||||||||
Net earnings attributable to PNMR | $ | 27.7 | $ | 21.5 | $ | 6.2 | $ | 38.3 | $ | 38.6 | $ | (0.3 | ) | ||||||||||
Average diluted common and common equivalent shares | 80.5 | 80.4 | 0.1 | 80.5 | 80.4 | 0.1 | |||||||||||||||||
Net earnings attributable to PNMR per diluted share | $ | 0.34 | $ | 0.27 | $ | 0.07 | $ | 0.48 | $ | 0.48 | $ | — |
Three Months Ended | Six Months Ended | ||||||
June 30, 2013 | June 30, 2013 | ||||||
(In millions) | |||||||
PNM | $ | 9.2 | $ | 3.0 | |||
TNMP | 0.3 | 1.1 | |||||
Corporate and Other | (3.4 | ) | (4.3 | ) | |||
Net change | $ | 6.2 | $ | (0.3 | ) |
• | Rate increases for PNM and TNMP - Additional information about these rate increases is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K and Note 10 |
• | Net unrealized gains and losses on mark-to-market economic hedges for sales and fuel costs not recoverable under PNM's FPPAC |
• | Higher prices for sales of power from PVNGS Unit 3 |
• | Lower retail load at PNM partially offset by higher retail load in the first quarter at TNMP |
• | Increased income tax expense due to impairments of state tax credits and a change in state tax rate (Note 13) |
• | Other factors impacting results of operation for each segment are discussed under Results of Operations below |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Electric operating revenues | $ | 279.7 | $ | 260.1 | $ | 19.6 | $ | 537.6 | $ | 510.5 | $ | 27.1 | |||||||||||
Cost of energy | 91.9 | 83.2 | 8.7 | 183.5 | 163.8 | 19.7 | |||||||||||||||||
Margin | 187.8 | 176.9 | 10.9 | 354.1 | 346.7 | 7.4 | |||||||||||||||||
Operating expenses | 103.5 | 106.2 | (2.7 | ) | 206.6 | 210.4 | (3.8 | ) | |||||||||||||||
Depreciation and amortization | 26.1 | 23.9 | 2.1 | 51.9 | 47.6 | 4.3 | |||||||||||||||||
Operating income | 58.3 | 46.7 | 11.6 | 95.5 | 88.8 | 6.7 | |||||||||||||||||
Other income (deductions) | 6.2 | 2.4 | 3.8 | 10.3 | 10.8 | (0.5 | ) | ||||||||||||||||
Net interest charges | (19.9 | ) | (18.9 | ) | (1.0 | ) | (39.8 | ) | (37.4 | ) | (2.4 | ) | |||||||||||
Segment earnings before income taxes | 44.6 | 30.2 | 14.4 | 66.0 | 62.1 | 3.9 | |||||||||||||||||
Income (taxes) | (14.9 | ) | (9.8 | ) | (5.1 | ) | (21.5 | ) | (20.7 | ) | (0.8 | ) | |||||||||||
Valencia non-controlling interest | (3.6 | ) | (3.5 | ) | (0.1 | ) | (6.8 | ) | (6.7 | ) | (0.1 | ) | |||||||||||
Preferred stock dividend requirements | (0.1 | ) | (0.1 | ) | — | (0.3 | ) | (0.3 | ) | — | |||||||||||||
Segment earnings | $ | 26.0 | $ | 16.8 | $ | 9.2 | $ | 37.4 | $ | 34.4 | $ | 3.0 |
2012/2013 Change | |||||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
Electric | Electric | ||||||||||||||||||||||
Operating | Cost of | Operating | Cost of | ||||||||||||||||||||
Revenues | Energy | Margin | Revenues | Energy | Margin | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Customer usage/load | $ | (2.8 | ) | $ | — | $ | (2.8 | ) | $ | (5.1 | ) | $ | — | $ | (5.1 | ) | |||||||
Weather | (0.8 | ) | — | (0.8 | ) | 0.1 | — | 0.1 | |||||||||||||||
Transmission and other | 7.7 | 7.1 | 0.6 | 17.4 | 17.8 | (0.4 | ) | ||||||||||||||||
Wholesale rate increases | — | — | — | 2.0 | — | 2.0 | |||||||||||||||||
Energy efficiency rider | (0.8 | ) | — | (0.8 | ) | (0.2 | ) | — | (0.2 | ) | |||||||||||||
Renewable energy rider | 6.4 | 3.2 | 3.2 | 11.2 | 4.6 | 6.6 | |||||||||||||||||
Unregulated margin | 0.7 | (2.2 | ) | 2.9 | 2.2 | (2.1 | ) | 4.3 | |||||||||||||||
Net unrealized economic hedges | 9.2 | 0.6 | 8.6 | (0.5 | ) | (0.6 | ) | 0.1 | |||||||||||||||
Net change | $ | 19.6 | $ | 8.7 | $ | 10.9 | $ | 27.1 | $ | 19.7 | $ | 7.4 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
(In millions, except customers) | |||||||||||||||||||||||
Residential | $ | 92.6 | $ | 93.0 | $ | (0.4 | ) | $ | 196.9 | $ | 192.7 | $ | 4.2 | ||||||||||
Commercial | 112.1 | 109.3 | 2.8 | 200.3 | 196.6 | 3.7 | |||||||||||||||||
Industrial | 19.2 | 19.2 | — | 36.6 | 37.2 | (0.6 | ) | ||||||||||||||||
Public authority | 6.5 | 6.0 | 0.5 | 11.8 | 11.3 | 0.5 | |||||||||||||||||
Economy service | 8.2 | 5.5 | 2.7 | 16.1 | 11.0 | 5.1 | |||||||||||||||||
Other retail | 2.4 | 2.6 | (0.2 | ) | 5.8 | 7.2 | (1.4 | ) | |||||||||||||||
Transmission | 9.3 | 9.6 | (0.3 | ) | 18.0 | 18.5 | (0.5 | ) | |||||||||||||||
Firm-requirements wholesale | 9.4 | 9.2 | 0.2 | 20.9 | 18.3 | 2.6 | |||||||||||||||||
Other sales for resale | 16.6 | 11.6 | 5.0 | 33.7 | 19.8 | 13.9 | |||||||||||||||||
Mark-to-market activity | 3.4 | (5.9 | ) | 9.3 | (2.5 | ) | (2.1 | ) | (0.4 | ) | |||||||||||||
$ | 279.7 | $ | 260.1 | $ | 19.6 | $ | 537.6 | $ | 510.5 | $ | 27.1 | ||||||||||||
Average retail customers (thousands) | 507.8 | 505.3 | 2.5 | 507.6 | 505.2 | 2.4 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||
(Gigawatt hours) | |||||||||||||||||
Residential | 735.9 | 760.4 | (24.5 | ) | 1,587.2 | 1,597.5 | (10.3 | ) | |||||||||
Commercial | 1,073.5 | 1,061.1 | 12.4 | 1,952.0 | 1,960.6 | (8.6 | ) | ||||||||||
Industrial | 274.2 | 285.8 | (11.6 | ) | 526.8 | 558.1 | (31.3 | ) | |||||||||
Public authority | 71.6 | 71.0 | 0.6 | 126.6 | 127.1 | (0.5 | ) | ||||||||||
Economy service | 176.9 | 141.8 | 35.1 | 353.6 | 283.3 | 70.3 | |||||||||||
Firm-requirements wholesale | 150.1 | 151.0 | (0.9 | ) | 327.3 | 323.8 | 3.5 | ||||||||||
Other sales for resale | 495.4 | 445.4 | 50.0 | 1,028.1 | 726.5 | 301.6 | |||||||||||
2,977.6 | 2,916.5 | 61.1 | 5,901.6 | 5,576.9 | 324.7 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Electric operating revenues | $ | 67.9 | $ | 63.8 | $ | 4.1 | $ | 127.7 | $ | 118.7 | $ | 9.0 | |||||||||||
Cost of energy | 13.8 | 11.5 | 2.3 | 26.9 | 22.8 | 4.1 | |||||||||||||||||
Margin | 54.1 | 52.3 | 1.8 | 100.8 | 96.0 | 4.9 | |||||||||||||||||
Operating expenses | 22.2 | 21.3 | 0.8 | 44.1 | 41.9 | 2.2 | |||||||||||||||||
Depreciation and amortization | 12.3 | 12.1 | 0.2 | 24.0 | 23.4 | 0.6 | |||||||||||||||||
Operating income | 19.7 | 18.9 | 0.8 | 32.7 | 30.7 | 2.0 | |||||||||||||||||
Other income (deductions) | 0.5 | 0.8 | (0.3 | ) | 0.7 | 0.9 | (0.2 | ) | |||||||||||||||
Net interest charges | (6.8 | ) | (7.1 | ) | 0.3 | (14.0 | ) | (14.2 | ) | 0.2 | |||||||||||||
Segment earnings before income taxes | 13.4 | 12.6 | 0.8 | 19.4 | 17.4 | 2.0 | |||||||||||||||||
Income (taxes) | (5.1 | ) | (4.6 | ) | (0.5 | ) | (7.3 | ) | (6.4 | ) | (1.0 | ) | |||||||||||
Segment earnings | $ | 8.3 | $ | 8.0 | $ | 0.3 | $ | 12.1 | $ | 11.0 | $ | 1.1 |
2012/2013 Change | |||||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
Electric | Electric | ||||||||||||||||||||||
Operating | Cost of | Operating | Cost of | ||||||||||||||||||||
Revenues | Energy | Margin | Revenues | Energy | Margin | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Rate increases | $ | 1.3 | $ | — | $ | 1.3 | $ | 2.0 | $ | — | $ | 2.0 | |||||||||||
Customer usage/load | — | — | — | 0.7 | — | 0.7 | |||||||||||||||||
Customer growth | 0.4 | — | 0.4 | 0.8 | — | 0.8 | |||||||||||||||||
Demand based customers | 1.4 | — | 1.4 | 1.6 | — | 1.6 | |||||||||||||||||
Weather | (1.5 | ) | — | (1.5 | ) | (1.3 | ) | — | (1.3 | ) | |||||||||||||
Transmission cost recovery | 2.3 | 2.3 | — | 4.5 | 4.1 | 0.4 | |||||||||||||||||
AMS surcharge | 1.1 | — | 1.1 | 2.1 | — | 2.1 | |||||||||||||||||
CTC surcharge | (1.1 | ) | — | (1.1 | ) | (1.8 | ) | — | (1.8 | ) | |||||||||||||
Other | 0.2 | — | 0.2 | 0.4 | — | 0.4 | |||||||||||||||||
Net change | $ | 4.1 | $ | 2.3 | $ | 1.8 | $ | 9.0 | $ | 4.1 | $ | 4.9 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
(In millions, except consumers) | |||||||||||||||||||||||
Residential | $ | 24.8 | $ | 25.8 | $ | (1.0 | ) | $ | 47.7 | $ | 46.6 | $ | 1.1 | ||||||||||
Commercial | 24.9 | 22.3 | 2.6 | 45.8 | 42.4 | 3.4 | |||||||||||||||||
Industrial | 3.4 | 3.5 | (0.1 | ) | 6.4 | 6.9 | (0.5 | ) | |||||||||||||||
Other | 14.8 | 12.2 | 2.6 | 27.8 | 22.8 | 5.0 | |||||||||||||||||
$ | 67.9 | $ | 63.8 | $ | 4.1 | $ | 127.7 | $ | 118.7 | $ | 9.0 | ||||||||||||
Average consumers (thousands) (1) | 234.7 | 232.9 | 1.8 | 234.4 | 232.4 | 2.0 |
(1) | TNMP provides transmission and distribution services to REPs that provide electric service to consumers in TNMP's service territories. The number of consumers above represents the customers of these REPs. Under TECA, consumers in Texas have the ability to choose any REP to provide energy. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||
(Gigawatt hours) | |||||||||||||||||
Residential | 651.2 | 726.3 | (75.1 | ) | 1,212.6 | 1,243.0 | (30.4 | ) | |||||||||
Commercial | 661.2 | 616.2 | 45.0 | 1,139.5 | 1,104.2 | 35.3 | |||||||||||
Industrial | 681.7 | 703.6 | (21.9 | ) | 1,234.2 | 1,330.2 | (96.0 | ) | |||||||||
Other | 28.3 | 27.7 | 0.6 | 49.7 | 51.6 | (1.9 | ) | ||||||||||
2,022.4 | 2,073.8 | (51.4 | ) | 3,636.0 | 3,729.0 | (93.0 | ) |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
(In millions) | |||||||||||||||||||||||
Total revenues | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||
Cost of energy | — | — | — | — | — | — | |||||||||||||||||
Margin | — | — | — | — | — | — | |||||||||||||||||
Operating expenses | (3.2 | ) | (4.6 | ) | 1.4 | (6.9 | ) | (7.9 | ) | 1.0 | |||||||||||||
Depreciation and amortization | 3.3 | 5.0 | (1.7 | ) | 6.6 | 8.5 | (1.9 | ) | |||||||||||||||
Operating income (loss) | (0.1 | ) | (0.5 | ) | 0.4 | 0.3 | (0.6 | ) | 0.9 | ||||||||||||||
Other income (deductions) | (2.2 | ) | (1.5 | ) | (0.7 | ) | (4.0 | ) | (4.1 | ) | 0.1 | ||||||||||||
Net interest charges | (4.0 | ) | (4.2 | ) | 0.2 | (8.1 | ) | (8.2 | ) | 0.1 | |||||||||||||
Segment earnings (loss) before income taxes | (6.3 | ) | (6.1 | ) | (0.2 | ) | (11.8 | ) | (12.9 | ) | 1.1 | ||||||||||||
Income (taxes) benefit | (0.3 | ) | 2.9 | (3.2 | ) | 0.6 | 6.0 | (5.4 | ) | ||||||||||||||
Segment earnings (loss) | $ | (6.7 | ) | $ | (3.3 | ) | $ | (3.4 | ) | $ | (11.2 | ) | $ | (6.9 | ) | (4.3 | ) |
Six Months Ended June 30, | |||||||||||
2013 | 2012 | Change | |||||||||
(In millions) | |||||||||||
Net cash flows from: | |||||||||||
Operating activities | $ | 159.9 | $ | 41.3 | $ | 118.6 | |||||
Investing activities | (143.1 | ) | (142.0 | ) | (1.1 | ) | |||||
Financing activities | 9.0 | 88.8 | (79.8 | ) | |||||||
Net change in cash and cash equivalents | $ | 25.8 | $ | (11.9 | ) | $ | 37.7 |
• | Upgrading generation resources and additional renewable energy projects |
• | Expanding the electric transmission and distribution systems |
• | Purchasing nuclear fuel |
2013 | 2014-2017 | Total | |||||||||
(In millions) | |||||||||||
Construction expenditures | $ | 389.8 | $ | 1,400.4 | $ | 1,790.2 | |||||
Dividends on PNMR common stock | 51.0 | 210.3 | 261.3 | ||||||||
Dividends on PNM preferred stock | 0.5 | 2.1 | 2.6 | ||||||||
Total capital requirements | $ | 441.3 | $ | 1,612.8 | $ | 2,054.1 |
PNMR | PNM | TNMP | |||
S&P | |||||
Senior secured debt | * | * | A- | ||
Senior unsecured debt | BBB- | BBB | * | ||
Preferred stock | * | BB+ | * | ||
Moody's | |||||
Senior secured debt | * | * | A3 | ||
Senior unsecured debt | Ba1 | Baa3 | * | ||
Preferred stock | * | Ba2 | * |
PNMR Separate | PNM Separate | TNMP Separate | PNMR Consolidated | ||||||||||||
(In millions) | |||||||||||||||
Financing capacity - revolving credit facility | $ | 300.0 | $ | 400.0 | $ | 75.0 | $ | 775.0 | |||||||
Amounts outstanding as of July 26, 2013: | |||||||||||||||
Revolving credit facility | 30.0 | — | 22.0 | 52.0 | |||||||||||
Letters of credit | 8.6 | 3.2 | 0.3 | 12.1 | |||||||||||
Total short–term debt and letters of credit | 38.6 | 3.2 | 22.3 | 64.1 | |||||||||||
Remaining availability as of July 26, 2013 | $ | 261.4 | $ | 396.8 | $ | 52.7 | $ | 710.9 | |||||||
Invested cash as of July 26, 2013 | $ | 3.1 | $ | 6.7 | $ | — | $ | 9.8 |
June 30, 2013 | December 31, 2012 | ||||
PNMR | |||||
PNMR common equity | 47.9 | % | 48.9 | % | |
Preferred stock of subsidiary | 0.3 | % | 0.3 | % | |
Long-term debt | 51.8 | % | 50.8 | % | |
Total capitalization | 100.0 | % | 100.0 | % | |
PNM | |||||
PNM common equity | 49.9 | % | 50.5 | % | |
Preferred stock | 0.4 | % | 0.5 | % | |
Long-term debt | 49.7 | % | 49.0 | % | |
Total capitalization | 100.0 | % | 100.0 | % | |
TNMP | |||||
Common equity | 58.4 | % | 59.8 | % | |
Long-term debt | 41.6 | % | 40.2 | % | |
Total capitalization | 100.0 | % | 100.0 | % |
• | The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions |
• | The ability of the Company to successfully forecast and manage its operating and capital expenditures |
• | State and federal regulatory, legislative, and judicial decisions and actions on ratemaking, tax, and other matters |
• | State and federal regulation or legislation relating to environmental matters, including the resultant costs of compliance and other impacts on the operations and economic viability of PNM's generating plants |
• | The impacts on the electricity usage of the Company's customers due to performance of state, regional, and national economies and mandatory energy efficiency measures, weather, seasonality, and other changes in supply and demand |
• | The risk that reliability standards regarding available transmission capacity and other FERC rulemakings may negatively impact the operation of PNM's transmission system |
• | The performance of generating units, transmission systems, and distribution systems, which could be negatively affected by operational issues, extreme weather conditions, terrorism, and cybersecurity breaches |
• | 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 |
• | Uncertainty surrounding the status of PNM's participation in jointly-owned generation projects resulting from the scheduled expiration of the operational and fuel supply agreements for the projects |
• | The risks associated with completion of generation, transmission, distribution, and other projects |
• | Regulatory, financial, and operational risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainties |
• | Uncertainty regarding the requirements and related costs of decommissioning power plants and coal mines supplying certain power plants, as well as the ability to recover decommissioning costs from customers |
• | The Company's ability to access the financial markets, including disruptions in the credit markets, actions by ratings agencies, and fluctuations in interest rates |
• | The potential unavailability of cash from PNMR's subsidiaries due to regulatory, statutory, or contractual restrictions |
• | The impacts of decreases in the values of marketable equity securities maintained to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits |
• | Commodity and counterparty credit risk transactions and the effectiveness of risk management |
• | The outcome of legal proceedings, including the extent of insurance coverage |
• | Changes in applicable accounting principles |
• | 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 |
Six Months Ended | |||||||
June 30, | |||||||
2013 | 2012 | ||||||
Economic Hedges | (In thousands) | ||||||
Sources of fair value gain (loss): | |||||||
Net fair value at beginning of period | $ | 1,204 | $ | (356 | ) | ||
Amount realized on contracts delivered during period | (964 | ) | (3,074 | ) | |||
Changes in fair value | (841 | ) | 1,096 | ||||
Net mark-to-market change recorded in earnings | (1,805 | ) | (1,978 | ) | |||
Net change recorded as regulatory assets and liabilities | 512 | 95 | |||||
Net fair value at end of period | $ | (89 | ) | $ | (2,239 | ) |
Settlement Dates | |||||||||||||||
2013 | 2014 | 2015 | 2016 | ||||||||||||
(In thousands) | |||||||||||||||
Economic hedges | |||||||||||||||
Prices actively quoted | $ | — | $ | — | $ | — | $ | — | |||||||
Prices provided by other external sources | 381 | 579 | (706 | ) | (343 | ) | |||||||||
Prices based on models and other valuations | — | — | — | — | |||||||||||
Total | $ | 381 | $ | 579 | $ | (706 | ) | $ | (343 | ) |
Rating (1) | Credit Risk Exposure(2) | Number of Counter-parties >10% | Net Exposure of Counter-parties >10% | |||||||
(Dollars in thousands) | ||||||||||
External ratings: | ||||||||||
Investment grade | $ | 5,699 | 2 | $ | 5,350 | |||||
Non-investment grade | — | — | — | |||||||
Split ratings | — | |||||||||
Internal ratings: | ||||||||||
Investment grade | 487 | — | — | |||||||
Non-investment grade | 159 | — | — | |||||||
Total | $ | 6,345 | $ | 5,350 |
(1) | The rating “Investment Grade” is for counterparties, or a guarantor, with a minimum S&P rating of BBB- or Moody's rating of Baa3. The category “Internal Ratings - Investment Grade” includes those counterparties that are internally rated as investment grade in accordance with the guidelines established in the Company’s credit policy. |
(2) | The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than firm-requirements wholesale customers), forward sales, and short-term sales. The exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by posted credit collateral. At June 30, 2013, PNMR held no credit collateral to offset its credit exposure. |
• | The Clean Air Act - Regional Haze - SJGS |
• | The Clean Air Act - Regional Haze - Four Corners |
• | The Clean Air Act - Four Corners BART FIP Challenge |
• | The Clean Air Act - Regional Haze Challenges |
• | The Clean Air Act - SJGS Operating Permit Challenge |
• | The Clean Air Act - WEG v. OSM NEPA Lawsuit |
• | The Clean Air Act - Citizen Suit Under the Clean Air Act |
• | The Clean Air Act - Four Corners Clean Air Act Lawsuit |
• | Navajo Nation Environmental Issues |
• | Endangered Species Act |
• | Santa Fe Generating Station |
• | PVNGS Water Supply Litigation |
• | San Juan River Adjudication |
• | Complaint Against Southwestern Public Service Company |
• | Navajo Nation Allottee Matters |
• | TGP Complaint |
• | PNM - Renewable Portfolio Standard |
• | PNM - Renewable Energy Rider |
• | PNM - Energy Efficiency and Load Management |
• | PNM - 2010 Electric Rate Case and FPPAC |
• | PNM - 2011 Integrated Resource Plan |
• | PNM - Emergency FFPAC |
• | PNM - Applications for Approvals to Purchase Delta |
• | PNM - Application for Approval of La Luz Generating Station |
• | PNM - Transmission Rate Case |
• | PNM - Formula Transmission Rate Case |
• | PNM - Tri-State Complaint |
• | PNM - Firm-Requirements Wholesale Customers |
• | TNMP - Advanced Meter System Deployment and Surcharge Request |
• | TNMP - Energy Efficiency |
• | TNMP - Transmission Cost of Service Rates |
3.1 | PNMR | Articles of Incorporation of PNMR, as amended to date (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed November 21, 2008) |
3.2 | PNM | Restated Articles of Incorporation of PNM, as amended through May 31, 2002 (incorporated by reference to Exhibit 3.1.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002) |
3.3 | TNMP | Articles of Incorporation of TNMP, as amended through July 7, 2005 (incorporated by reference to Exhibit 3.1.2 to TNMP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005) |
3.4 | PNMR | Bylaws of PNMR, with all amendments to and including December 8, 2009 (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed December 11, 2009) |
3.5 | PNM | Bylaws of PNM, with all amendments to and including May 31, 2002 (incorporated by reference to Exhibit 3.1.2 to PNM’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002) |
3.6 | TNMP | Bylaws of TNMP, with all amendments to and including June 18, 2013 (incorporated by reference to Exhibit 3.6 to TNMP's Current Report on Form 8-K filed June 20, 2013) |
12.1 | PNMR | Ratio of Earnings to Fixed Charges |
12.2 | PNM | Ratio of Earnings to Fixed Charges |
12.3 | TNMP | Ratio of Earnings to Fixed Charges |
31.1 | PNMR | Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
31.2 | PNMR | Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
31.3 | PNM | Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
31.4 | PNM | Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
31.5 | TNMP | Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
31.6 | TNMP | Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
32.1 | PNMR | Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
32.2 | PNM | Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
32.3 | TNMP | Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
101.INS | PNMR, PNM, and TNMP | XBRL Instance Document |
101.SCH | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Schema Document |
101.CAL | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | PNMR, PNM, and TNMP | XBRL Taxonomy Extension Presentation Linkbase Document |
PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY | ||
(Registrants) | ||
Date: | August 2, 2013 | /s/ Thomas G. Sategna |
Thomas G. Sategna | ||
Vice President and Corporate Controller | ||
(Officer duly authorized to sign this report) |
Exhibit 12.1 | |||||||||||||||||||||||||
PNM RESOURCES, INC. AND SUBSIDIARIES | |||||||||||||||||||||||||
Ratio of Earnings to Fixed Charges | |||||||||||||||||||||||||
(In thousands, except ratio) | |||||||||||||||||||||||||
Six Months Ended | Year Ended December 31, | ||||||||||||||||||||||||
June 30, 2013 | 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||||||
Fixed charges, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Interest expensed and capitalized | $ | 60,438 | $ | 125,379 | $ | 122,998 | $ | 123,633 | $ | 123,833 | $ | 134,958 | |||||||||||||
Amortization of debt premium, discount and expenses | 1,964 | 4,023 | 3,695 | 4,627 | 5,430 | 6,386 | |||||||||||||||||||
Interest from discontinued operations (including capitalized interest) | — | — | — | — | 1,027 | 13,758 | |||||||||||||||||||
Estimated interest factor of lease rental charges | 2,924 | 5,585 | 6,665 | 6,888 | 7,034 | 7,894 | |||||||||||||||||||
Preferred dividend requirements of subsidiary | 429 | 769 | 864 | 1,075 | 759 | 689 | |||||||||||||||||||
Total Fixed Charges | $ | 65,755 | $ | 135,756 | $ | 134,222 | $ | 136,223 | $ | 138,083 | $ | 163,685 | |||||||||||||
Earnings, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Earnings (loss) from continuing operations before income taxes and non-controlling interest | $ | 73,648 | $ | 175,035 | $ | 321,469 | $ | (63,379 | ) | $ | 94,751 | $ | (388,381 | ) | |||||||||||
(Earnings) loss of equity investee | — | — | — | 15,223 | 30,145 | 29,687 | |||||||||||||||||||
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings | 73,648 | 175,035 | 321,469 | (48,156 | ) | 124,896 | (358,694 | ) | |||||||||||||||||
Fixed charges as above | 65,755 | 135,756 | 134,222 | 136,223 | 138,083 | 163,685 | |||||||||||||||||||
Interest capitalized | (2,279 | ) | (5,432 | ) | (2,697 | ) | (3,401 | ) | (7,743 | ) | (8,849 | ) | |||||||||||||
Non-controlling interest in earnings of Valencia | (6,777 | ) | (14,050 | ) | (14,047 | ) | (13,563 | ) | (11,890 | ) | (7,179 | ) | |||||||||||||
Preferred dividend requirements of subsidiary | (429 | ) | (769 | ) | (864 | ) | (1,075 | ) | (759 | ) | (689 | ) | |||||||||||||
Earnings Available for Fixed Charges | $ | 129,918 | $ | 290,540 | $ | 438,083 | $ | 70,028 | $ | 242,587 | $ | (211,726 | ) | ||||||||||||
Ratio of Earnings to Fixed Charges | 1.98 | 2.14 | 3.26 | 1 | 0.51 | 2 | 1.76 | N/M | 3 | ||||||||||||||||
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes a pre-tax loss of $21.4 million due to the write-off of regulatory disallowances at PNM and TNMP. If those losses were excluded, the Ratio of Earnings to Fixed Charges would have been 3.42. In addition, 2011 includes a pre-tax gain on the sale of First Choice of $174.9 million. If that gain were also excluded, the Ratio of Earnings to Fixed Charges would have been 1.96. | |||||||||||||||||||||||||
2 The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $66.2 million for the year ended December 31, 2010. Earnings (loss) from continuing operations before income taxes and non-controlling interest includes a pre-tax loss of $188.2 million due to the impairment of PNMR's investment in an equity investee. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 1.90. | |||||||||||||||||||||||||
3 The ratio of earnings to fixed charges for the year ended December 31, 2008 is not meaningful since earnings available for fixed charges is negative. The shortfall in the earnings available to achieve a ratio of earnings to fixed charges of 1.00 amounted to $375.4 million for the year ended December 31, 2008. |
Exhibit 12.2 | |||||||||||||||||||||||||
PUBLIC SERVICE COMPANY OF NEW MEXICO | |||||||||||||||||||||||||
Ratio of Earnings to Fixed Charges | |||||||||||||||||||||||||
(In thousands, except ratio) | |||||||||||||||||||||||||
Six Months Ended | Year Ended December 31, | ||||||||||||||||||||||||
June 30, 2013 | 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||||||||
Fixed charges, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Interest expensed and capitalized | $ | 39,905 | $ | 82,864 | $ | 75,217 | $ | 73,423 | $ | 73,104 | $ | 72,427 | |||||||||||||
Amortization of debt premium, discount and expenses | 941 | 1,818 | 1,325 | 1,274 | 1,336 | 4,345 | |||||||||||||||||||
Interest from discontinued operations (including capitalized interest) | — | — | — | — | 1,027 | 13,758 | |||||||||||||||||||
Estimated interest factor of lease rental charges | 1,880 | 3,743 | 4,139 | 4,103 | 4,517 | 4,553 | |||||||||||||||||||
Total Fixed Charges | $ | 42,726 | $ | 88,425 | $ | 80,681 | $ | 78,800 | $ | 79,984 | $ | 95,083 | |||||||||||||
Earnings, as defined by the Securities and Exchange Commission: | |||||||||||||||||||||||||
Earnings (loss) from continuing operations before income taxes and non-controlling interest | $ | 66,002 | $ | 156,314 | $ | 105,965 | $ | 107,288 | $ | 45,627 | $ | (69,324 | ) | ||||||||||||
Fixed charges as above | 42,726 | 88,425 | 80,681 | 78,800 | 79,984 | 95,083 | |||||||||||||||||||
Non-controlling interest in earnings of Valencia | (6,777 | ) | (14,050 | ) | (14,047 | ) | (13,563 | ) | (11,890 | ) | (7,179 | ) | |||||||||||||
Interest capitalized | (1,896 | ) | (4,314 | ) | (1,761 | ) | (2,811 | ) | (6,067 | ) | (7,363 | ) | |||||||||||||
Earnings Available for Fixed Charges | $ | 100,055 | $ | 226,375 | $ | 170,838 | $ | 169,714 | $ | 107,654 | $ | 11,217 | |||||||||||||
Ratio of Earnings to Fixed Charges | 2.34 | 2.56 | 2.12 | 1 | 2.15 | 1.35 | 0.12 | 2 | |||||||||||||||||
1 Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes a pre-tax loss $17.5 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.33. | |||||||||||||||||||||||||
2 The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $83.9 million for the year December 31, 2008. |
Exhibit 12.3 | ||||||||||||||||||||||||
TEXAS-NEW MEXICO POWER COMPANY | ||||||||||||||||||||||||
Ratio of Earnings to Fixed Charges | ||||||||||||||||||||||||
(In thousands, except ratio) | ||||||||||||||||||||||||
Six Months Ended | Year Ended December 31, | |||||||||||||||||||||||
June 30, 2013 | 2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||||||
Fixed charges, as defined by the Securities and Exchange Commission: | ||||||||||||||||||||||||
Interest expensed and capitalized | $ | 12,675 | $ | 26,233 | $ | 27,914 | $ | 28,632 | $ | 25,609 | $ | 17,861 | ||||||||||||
Amortization of debt premium, discount and expenses | 672 | 1,493 | 1,679 | 2,683 | 3,355 | 1,504 | ||||||||||||||||||
Estimated interest factor of lease rental charges | 589 | 956 | 1,202 | 1,246 | 831 | 571 | ||||||||||||||||||
Total Fixed Charges | $ | 13,936 | $ | 28,682 | $ | 30,795 | $ | 32,561 | $ | 29,795 | $ | 19,936 | ||||||||||||
Earnings, as defined by the Securities and Exchange Commission: | ||||||||||||||||||||||||
Earnings from continuing operations before income taxes | $ | 19,410 | $ | 42,099 | $ | 36,138 | $ | 26,026 | $ | 20,151 | $ | 2,335 | ||||||||||||
Fixed charges as above | 13,936 | 28,682 | 30,795 | 32,561 | 29,795 | 19,936 | ||||||||||||||||||
Interest capitalized | (237 | ) | (706 | ) | (593 | ) | (158 | ) | (1,144 | ) | (1,025 | ) | ||||||||||||
Earnings Available for Fixed Charges | $ | 33,109 | $ | 70,075 | $ | 66,340 | $ | 58,429 | $ | 48,802 | $ | 21,246 | ||||||||||||
Ratio of Earnings to Fixed Charges | 2.38 | 2.44 | 2.15 | 1 | 1.79 | 1.64 | 1.07 | |||||||||||||||||
1 Earnings from continuing operations before income taxes for the year ended December 31, 2011 includes a pre-tax loss of $3.9 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.28. | ||||||||||||||||||||||||
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, 2013 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
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, 2013 | 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, 2013 | 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, 2013 | 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, 2013 | 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, 2013 | By: | /s/ Thomas G. Sategna |
Thomas G. Sategna | |||
Vice President and Controller | |||
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, 2013 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
President and Chief Executive Officer | |||
PNM Resources, Inc. | |||
By: | /s/ Charles N. Eldred | ||
Charles N. Eldred | |||
Executive Vice President and | |||
Chief Financial Officer |
(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, 2013 | 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, 2013 | By: | /s/ Patricia K. Collawn |
Patricia K. Collawn | |||
Chief Executive Officer | |||
Texas-New Mexico Power Company | |||
By: | /s/ Thomas G. Sategna | ||
Thomas G. Sategna | |||
Vice President and Controller | |||
Texas-New Mexico Power Company |
Commitments and Contingencies
|
6 Months Ended |
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Jun. 30, 2013
|
|
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Overview There are various claims and lawsuits pending against the Company. The Company is also 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 occasionally enters into financial commitments in connection with its business operations. The Company is also involved in various legal and regulatory (Note 10) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows. With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. 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 2012 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 under the contract. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE's delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. The PVNGS owners previously received a damages award for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007, through June 30, 2011, APS, as a co-owner of PVNGS, incurred additional damages due to DOE's continuing failure to remove spent nuclear fuel and high level waste from PVNGS. Activities in this legal proceeding are currently limited to review by the government of supporting information for APS's claim. PNM is unable to predict the outcome of this matter. PNM estimates that it will incur approximately $42.8 million (in 2010 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At June 30, 2013 and December 31, 2012, PNM had a liability for interim storage costs of $12.3 million and $13.9 million included in other deferred credits. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC's rulemaking regarding temporary storage and permanent disposal of high-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC's 2010 update to the agency's Waste Confidence Decision. The D.C. Circuit found that the agency's 2010 Waste Confidence Decision update constituted a major federal action, which requires either an environmental impact statement or a finding of no significant impact from the agency's actions. The D.C. Circuit found that the NRC's evaluation of the environmental risks from spent nuclear was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic environmental impact statement to support an updated Waste Confidence Decision within 24 months. PNM is unable to predict the impact that the decision may have on the operation of PVNGS. The Clean Air Act Regional Haze In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, the EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018. SJGS SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that requires installation of selective catalytic reduction technology (“SCR”) with stringent NOx emission limits on all four units by September 21, 2016. PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA's decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule on March 1, 2012. These parties have also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA's rule in the Tenth Circuit, seeking to shorten its compliance period from five years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court's order, the parties have filed supplemental information. No decision has been announced and there is no deadline for a court decision. In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico's regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree. Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014. PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs would be refined through an “open book” subcontractor bidding process. The costs for the project to install SCRs would encompass installation of technology to comply with the NAAQS requirements described below. PNM previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. The estimates for SNCRs and the NAAQS requirements include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM's share of the costs under either SCRs or SNCRs as described above would be about 46.3%. During 2012 and early 2013, PNM engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. On February 15, 2013, PNM, NMED, and EPA agreed to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP. The revised plan would require approval by EIB and EPA. NMPRC approval of the retirement of SJGS Units 2 and 3 and plans for PNM to acquire power to replace its reduced capacity from SJGS would also be part of implementation. PNM also anticipates requesting approval to recover from ratepayers the unrecovered investment in SJGS Units 2 and 3 and costs incurred to retire those units. PNM anticipates filing for the required NMPRC approvals in December 2013. On July 10, 2013, the NMPRC issued an order initiating a proceeding regarding the possible retirement of SJGS Units 2 and 3 and impacts on service reliability, and other items. The order requires PNM to make monthly presentations to the NMPRC on this matter. At June 30, 2013, PNM's net book value of SJGS Units 2 and 3 was approximately $289 million. In accordance with the revised plan, PNM submitted a new BART analysis to the NMED on April 1, 2013, reflecting the terms of the non-binding agreement, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3, NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. The EIB will conduct a public hearing on the revised SIP on September 5 and 6, 2013. Upon approval by EIB, the revised SIP will be submitted to EPA for approval. EIB approval is projected for the fourth quarter of 2013, with EPA action in late 2014. Due to the long lead times on certain equipment purchases, PNM is taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract. In connection with the implementation of the plan, retirement of SJGS Units 2 and 3 could result in shifts in ownership among SJGS owners as may be agreed upon by the owners, including PNM acquiring additional ownership in SJGS Unit 4. Owners of the affected units also may seek approvals of their utility commissions or governing boards. This revised plan primarily focuses on how SJGS would meet the regional haze rule, but also indicates that PNM would build a natural gas-fired generating plant to be sited at SJGS to partially replace the capacity from the retired coal units. Detailed replacement power strategies also would be finalized. PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability. Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the terms agreed to do not move forward due to circumstances outside of the control of PNM and NMED, EPA will work with the State of New Mexico and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the revised SIP. PNM is also exploring potential additional areas of relief, including relief from the Tenth Circuit. On February 25, 2013, the parties filed their status reports with the Tenth Circuit. To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the Tenth Circuit. Following the parties' submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals. If the February 15, 2013 plan described above is implemented, PNM currently estimates its share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 would be approximately $60 million to $80 million, including gross receipts taxes, AFUDC, and other PNM costs. This amount is based on the anticipation that PNM's ownership share of SJGS Units 1 and 4 would aggregate to approximately 52%. PNM also estimates that the cost of replacing a portion of PNM's share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3 with identified gas-fired peaking capacity would be approximately $280 million. Neither of these amounts is included in PNM's current construction expenditure forecast since approval of the plan is subject to numerous conditions. Additional base load generating capacity may be required to replace a portion of retired SJGS capacity. Although the nature of additional base load capacity has not yet been identified, it could come from PVNGS Unit 3 or additional gas-fired generation. Operating costs would also increase with the installation of either SCRs or SNCRs. PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished at all or within the required timeframes. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would likely seek relief from the compliance deadline from EPA or the Tenth Circuit in order to continue to be able to operate the plant during the completion of the installation process. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM's needs or, if available, what costs would be incurred. PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS. PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability of individual participants to continue participation in the plant. Four Corners On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule includes two compliance alternatives. The first emission control strategy finalized by EPA would require the installation of post-combustion controls, including SCRs, on each of Units 1-5 at Four Corners to reduce NOx emissions. Under the second emission control alternative, the owners of Four Corners would have the option to close permanently Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners' coal and material handling operations. Under the EPA's final BART determination, the Four Corners participants had until July 1, 2013 to notify EPA of which emission control strategy Four Corners would follow. On June 19, 2013, APS requested EPA to extend the notification date to December 31, 2013 due to new uncertainties surrounding the potential impacts of the May 9, 2013 announcement by the Arizona Corporation Commission ("ACC"), which regulates APS, to examine whether to deregulate the state's electric market and introduce open competition to consumers. On July 11, 2013, EPA published a proposed rule in the Federal Register granting the extension. The Four Corners participants' obligations to comply with EPA's final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners. PNM is continuing to evaluate the impacts of EPA's BART determination for Four Corners. PNM estimates its share of costs, including PNM's AFUDC, to be up to approximately $75 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM has no ownership interest in Four Corners Units 1, 2, and 3. PNM is unable to predict the ultimate outcome of this matter. SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE's 48% interest in each of Units 4 and 5 of Four Corners. A principal remaining condition to closing is the negotiation and execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below. APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will shut down Units 1, 2, and 3 at Four Corners. In light of the ACC's announcement to re-examine whether to deregulate the retail electric market in Arizona, APS has announced that it currently expects it will not be in a position to close the Four Corners purchase transaction with SCE until the ACC's intentions with regard to pursuing deregulation in Arizona become clearer. Four Corners BART FIP Challenge On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP. In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA. APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS' motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. This matter is now proceeding in the Tenth Circuit. PNM cannot currently predict the outcome of this matter or the range of its potential impact. Regional Haze Challenges On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO2 and particulate matter emissions elements of EPA's approval of New Mexico's Regional Haze SIP. On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA's final approval of the remaining elements of New Mexico's Regional Haze SIP, as well as EPA's approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. The parties are in the process of briefing their respective positions. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes. SJGS Operating Permit Challenge On February 16, 2012, EPA issued its response to a WEG petition objecting to SJGS's operating permit granted by the NMED in January 2011. In its order, EPA required NMED to provide clarification on several of the matters raised by WEG. EPA's order in this matter does not constitute a finding that the plant has violated any provision of the CAA or that it has violated any emission limits. In August 2012, NMED issued a response to the EPA order stating that SJGS's operating permit would be reopened to make certain modifications to the permit. NMED issued a public notice regarding proposed modifications to the SJGS operating permit on September 19, 2012 and issued a revised operating permit on November 26, 2012. The revised permit includes changes to the SO2 and particulate matter emission limits that were previously incorporated into the SJGS NSR permit. In addition, the revised permit requires PNM to submit a compliance plan to address carbon monoxide (“CO”) emissions increases at SJGS Unit 2. PNM submitted a compliance plan in May 2013 and considers this matter resolved. WEG v. OSM NEPA Lawsuit In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC's San Juan mine. WEG's allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act violations against OSM including, but not limited to, OSM's alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG's petition seeks various forms of relief, including voiding, reversing and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, and enjoining operations at the seven mines. SJCC intervened in this matter and seeks to sever SJCC's claims from the lawsuit and transfer venue to the New Mexico federal court. PNM cannot currently predict the outcome of this matter or the range of its potential impact. National Ambient Air Quality Standards (“NAAQS”) The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO2, ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO2 NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO2 and the 24-hour SO2 standard. New Mexico is in attainment for the 1-hour NOx NAAQS. EPA has issued draft guidance on how to determine whether areas in a state comply with the new 1-hour SO2 NAAQS. On May 21, 2013, the EPA released draft guidance on characterizing air quality in areas with limited or no monitoring data near existing SO2 sources. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO2 NAAQS. Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO2 standard may require operational changes and/or equipment modifications at SJGS. On June 4, 2013, Sierra Club and National Resource Defense Council issued a NOI to sue EPA for failure to issue non-attainment designations for areas they claim to be in violation of the 2010 1-hour SO2 standard. On April 6, 2012, PNM filed an application for an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In addition, this application included a proposal by PNM to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO2, and particulate matter. These modifications would help SJGS meet the NAAQS. It is anticipated that this technology would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze - SJGS above. EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM is currently evaluating the impact of the revised standard on SJGS and its operations. In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and is scheduled to propose a new standard in December 2013 and finalize it by the end of 2014. Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required as a result of ozone non-attainment designation. Citizen Suit Under the Clean Air Act The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS's emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties' dispute is deemed settled. In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM's mercury controls. NMED and plaintiffs seek to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.6 million, to a total of $6.1 million. The court appointed a special master to evaluate the technical arguments in the case and to address the detection and determination limits of the mercury monitors at SJGS and the appropriate brominated activated carbon injection rate that maximizes the reduction of mercury emissions from SJGS. The special master issued a report indicating he was unable to make a determination on either of these issues. In September 2012, PNM submitted objections to certain portions of the special master report and requested an evidentiary hearing. Also in September 2012, NMED and plaintiffs filed a motion asking the court to affirm certain findings in the special master report and order PNM to conduct additional mercury testing. PNM cannot predict the outcome of this matter. Section 114 Request In April 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. EPA has taken the position that many utilities have made physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. APS has responded to EPA's request. PNM is currently unable to predict the timing or content of EPA's response, if any, or any resulting actions. Four Corners Clean Air Act Lawsuit In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners participants may reinstate their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact. Navajo Nation Environmental Issues Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation's authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts. Endangered Species Act In January 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the OSM and the DOI, alleging that OSM failed to engage in mandatory ESA consultation with the United States Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners. The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats. The lawsuit requested the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA. Neither PNM nor APS was a party to the lawsuit. On March 14, 2012, the Court entered an order dismissing the plaintiffs' lawsuit without prejudice. On May 14, 2012, the plaintiffs appealed the Court's order to the Tenth Circuit. On July 8, 2013, the Tenth Circuit entered an order dismissing the appeal. Cooling Water Intake Structures EPA issued its proposed cooling water intake structures rule in April 2011, which would provide national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The proposed rule would require facilities such as Four Corners and SJGS to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity and to take certain protective measures with respect to impinged fish. The proposed rule would also require these facilities to either meet the definition of a closed cycle recirculating cooling system or conduct a “structured site-specific analysis” to determine what site-specific controls, if any, should be required. The proposed rule would require existing facilities to comply with the impingement mortality requirements as soon as possible, but no later than eight years after the effective date of the rule, and to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. EPA was required to issue a final rule by June 27, 2013; however, that date has been extended to November 4, 2013. PNM and APS continue to follow the rulemaking and are performing analyses to determine the potential costs of compliance with the proposed rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. Effluent Limitation Guidelines On June 7, 2013, EPA published proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for steam electric power plants. EPA's proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning wastes operations. EPA is subject to a consent decree deadline to finalize the revised guidelines by May 22, 2014. PNM is in the process of reviewing the proposed rule to assess the impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. APS is currently assessing the impact to Four Corners. PNM is unable to predict the outcome of this matter or if it will have a material impact on PNM's financial position, results of operations, or cash flows. 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 the 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 municipal well continues to operate and meets federal drinking water standards. PNM is not able to assess the duration of this project. The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM's obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, but has not yet provided PNM any data from the recent tests. PNM is unable to predict the outcome of this matter, but does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons. Coal Combustion Byproducts Waste Disposal CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production. Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer's Office. In June 2010, EPA published a proposed rule that includes two options for waste designation of coal ash. One option is to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA's proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule. On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA's regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary. They also claim that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated. PNM advocates for the non-hazardous regulation of CCBs. However, if CCBs are ultimately regulated as a hazardous waste, costs could increase significantly. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of EPA's or OSM's proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material impact on its operations, financial position, or cash flows. Hazardous Air Pollutants (“HAPs”) Rulemaking In December 2011, the EPA issued its final Mercury and Air Toxics Standards (“MATS”) to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities will generally have up to four years to demonstrate compliance with the new rule. PNM's assessment of MATS indicates that the control equipment currently used at SJGS allows the plant to meet the emission standards set forth in the rule although the plant may be required to install additional monitoring equipment. With regard to mercury, stack testing performed for EPA during the MATS rulemaking process showed that SJGS achieved a mercury removal rate of 99% or greater. APS has determined that no additional equipment will be required at Four Corners to comply with the rule. Other Commitments and Contingencies Coal Supply The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At June 30, 2013 and December 31, 2012, prepayments for coal, which are included in other current assets, amounted to $14.9 million and $9.9 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017. APS purchases all of Four Corners' coal requirements from a supplier that is also a subsidiary of BHP and has a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through July 6, 2016 with pricing determined using an escalating base-price. In December 2012, BHP announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which the coal mine would be sold to the Navajo Nation. The BHP subsidiary would be retained as the mine manager and operator until July 2016. Key terms of the new coal supply contract are being finalized by the Navajo Nation and the Four Corners owners. As a result of this proposed change in ownership, APS expected that a new coal supply contract would be executed upon completion of negotiations and following the endorsement of the transfer of ownership to a new Navajo Nation commercial enterprise to be established by the Navajo Nation Tribal Council. On April 29, 2013, the Navajo Nation Tribal Council approved the creation of the new commercial enterprise with sufficient power and authority to execute the transaction with BHP. These negotiations, and the related transaction whereby full ownership of the coal mine would be transferred to the Navajo Nation, are proceeding. See The Clean Air Act - Regional Haze - Four Corners above. PNM is unable to predict the outcome of this matter. In 2010, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. The estimate for decommissioning the Four Corners mine was also revised in 2010. Based on the most recent estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $58.9 million for the surface mines at both SJGS and Four Corners and $19.7 million for the underground mine at SJGS as of June 30, 2013. At June 30, 2013 and December 31, 2012, liabilities, in current dollars, of $25.4 million and $26.8 million for surface mine reclamation and $4.5 million and $4.2 million for underground mine reclamation were recorded in other deferred credits. PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. San Juan Underground Mine Fire Incident On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration (“MSHA”) was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. If further difficulties occur in the longwall mining operation, PNM and the other owners of SJGS would need to consider alternatives for operating SJGS, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time. The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM anticipates that it will recover through its FPPAC the portion of such costs allocable to its customers subject to New Mexico regulation. PNM's filings with the NMPRC reflect an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by $21.6 million. SJCC has submitted an insurance claim regarding the costs it incurred due to the mine fire. Any recovery obtained by SJCC through its insurance carrier may be reimbursable (in whole or in part) to PNM through the coal sales agreement. Any insurance recovery would be flowed through PNM's FPPAC to the extent it relates to increased coal costs included in the FPPAC. The potential impacts of any insurance settlement cannot be determined at the current time. Based on information PNM has received from SJCC to date, PNM does not expect the mine fire to have a material effect on its financial condition, results of operations, or cash flows. Nuclear Fuel In late August 2012, one of PVNGS's suppliers that converts uranium concentrates to uranium hexafluoride invoked the force majeure provision in its contract when it shut down its conversion plant due to regulatory compliance issues. The issues have been resolved and the conversion plant has restarted. The PVNGS participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The PVNGS participants have sufficient strategic reserves of enriched uranium such that they do not anticipate a short-term impact on nuclear fuel supplies as a result of the force majeure declaration. PVNGS Liability and Insurance Matters Liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $12.6 billion per occurrence. Commercial insurance carriers provide $375 million and $12.2 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 assessment per incident for all three units is $36.0 million, with an annual payment limitation of $5.4 million. The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL's losses in any policy year exceed accumulated funds, PNM is subject to retrospective assessments of $4.3 million for each retrospective assessment declared by NEIL's Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions. Water Supply Because of New Mexico's arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Delta, Afton, Luna, and Lordsburg. Water availability does not appear to be an issue for these plants at this time. However, prolonged drought, ESA activities and a Federal lawsuit by the State of Texas suing the State of New Mexico over water allocations could pose a threat of reduced water availability for these plants. PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future. In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years. PVNGS Water Supply Litigation In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court's jurisdiction over PVNGS' groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court's criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows. San Juan River Adjudication In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees. The court has ordered that settlement of the Navajo Nation's claims under the settlement agreement and entry of the proposed decrees be heard in an expedited proceeding. The court recently issued an order finding that no evidentiary hearing is warranted in the Navajo Nation proceeding, and that it will be issuing an order addressing the issues raised by the parties at some point in the future. This order must be entered no later than December 31, 2013, pursuant to the 2005 settlement. PNM's water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. Therefore, PNM has elected to participate in this proceeding. The Company 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. Complaint Against Southwestern Public Service Company In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS' fuel cost adjustment clause practices (the “Golden Spread proceeding”). In 2008, FERC issued its order in the Golden Spread proceeding affirming that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues. PNM and SPS have filed petitions for rehearing and clarification of the scope of the remedies that were ordered and reversal of various rulings in the order. FERC has not yet acted upon the requests for rehearing or clarification and they remain pending further decision. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes. Navajo Nation Allottee Matters A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court in Albuquerque. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. In March 2010, the court ordered that the entirety of the plaintiffs' case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court. In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs ("BIA"), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director's decision to the DOI Board of Appeals. Briefings on the merits of the appeal are complete and a decision is pending. PNM is participating in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time. In a separate matter, in September 2012, forty-three landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. PNM is participating in this matter in order to preserve its interests regarding the right-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time. TGP Complaint On March 2, 2012, TGP Granada, LLC and its affiliate (collectively, “TGP”) filed a complaint at FERC against PNM and Tortoise Capital Resources Corp. (“TTO”). PNM owns 60% of the EIP and leases the other 40% from TTO. PNM's lease of the portion of the EIP owned by TTO expires on April 1, 2015. The lease provides PNM the option, with 24 months advance notice, of purchasing the leased assets at the end of the lease for fair market value, as well as options to renew the lease. TGP's filing requested FERC to direct PNM and TTO to identify the party that will immediately assume the obligation of making transmission capacity on the EIP available to customers for use after the April 1, 2015 expiration of the EIP lease agreement. TGP also requested a declaratory order or waiver regarding certain provisions of PNM's Open Access Transmission Tariff to allow its affiliate to change the point-of-receipt associated with a transmission service agreement related to the EIP without losing its transmission service priority. On July 5, 2012, FERC issued an order denying TGP's requests for declaratory order and waiver. In addition, FERC directed PNM, in consultation with TTO, to identify the party that will provide long-term transmission service over the leased portion of the EIP. On November 1, 2012, PNM and TTO entered into a definitive agreement for PNM to exercise the option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. The lease remains in existence and PNM will record the purchase at the termination of the lease on April 1, 2015. The definitive agreement sets forth the terms and conditions under which PNM would also assume responsibility for scheduling long-term transmission service on the leased capacity. In November 2012, PNM requested the necessary FERC approvals for the definitive agreement. In January 2013, FERC approved PNM's requests. On February 8, 2013, FERC issued an order dismissing as moot a motion filed by TGP for clarification of FERC's July 5, 2012 order. Since no rehearing request or appeal was filed, the February 8, 2013 order is final and non-appealable. |
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Segment Information | Segment Information The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided. PNM PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the general wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM's jurisdictional capacity, as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale and transmission rates. TNMP TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP's operations are subject to traditional rate regulation by the PUCT. Corporate and Other The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. PNMR SEGMENT INFORMATION
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Jun. 30, 2013
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment [Table Text Block] | 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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Regulatory and Rate Matters
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6 Months Ended |
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Jun. 30, 2013
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Regulatory and Rate Matters | |
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 9. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K. PNM Renewable Portfolio Standard The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” Prior to December 2012, the diversity requirements were 20% from wind energy, 20% from solar energy, 10% from other renewable technologies, and 1.5% from distributed generation with the distributed generation component increasing to 3% in 2015. In December 2012, NMPRC issued an order that amended the diversity requirements to 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, and adopted other changes to its renewable energy rule, including the increase in the RCT discussed below. In June 2013, the NMPRC initiated a new rulemaking proceeding in which it proposed to eliminate specific diversity targets and to reconsider the inclusion of avoided environmental and capacity costs in the application of the RCT. A public hearing is scheduled for September 10, 2013. The REA provides for streamlined proceedings for approval of utilities' renewable energy procurement plans, assures utilities recovery of 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 NMPRC had established a RCT for 2011 of 2% of all customers' aggregated overall annual electric charges that increased by 0.25% annually until reaching 3% in 2015. In December 2012, the NMPRC approved an amended RCT set at 3% of customers' annual electric charges beginning in 2013 and continuing thereafter. In July 2011, PNM filed its renewable energy procurement plan for 2012. The plan requested a variance from the RPS due to RCT limitations. The plan was diversity-compliant based on the reduced RPS, except for non-wind/non-solar resources, which were not available. In December 2011, the NMPRC approved PNM's 2012 plan, but ordered PNM to spend an additional $0.9 million on renewable procurements in 2012. PNM is recovering the costs of the supplemental procurements through the renewable rider discussed below. The NMPRC also required PNM to file its 2013 renewable energy procurement plan by April 30, 2012. The 2013 plan proposed procurements for 2013 and 2014 of 20 MW of PNM-owned solar PV facilities, at an estimated cost of $45.5 million, wind and solar REC purchases in 2013, and a PPA for the output of a new 10 MW geothermal facility. The plan also included an additional procurement of 2 MW of PNM-owned solar PV facilities at an estimated cost of $4.5 million to supply the energy sold under PNM's voluntary renewable energy tariff. The plan will enable PNM to comply with the statutory RPS amount in 2013, but requires a variance from the NMPRC's diversity requirements in 2013 while the proposed geothermal facilities are being constructed. This plan had been expected to achieve full RPS quantity and diversity compliance by 2014 without exceeding the RCT. The NMPRC approved the plan in December 2012, but reduced the additional solar PV procurement from 2 MW to 1.5 MW. Construction of the geothermal facility has been delayed due to a longer than expected permitting process. This will delay the in-service date of the geothermal facility until later in 2014. PNM does not believe this delay will affect its ability to comply with the diversity requirements as amended in December 2012. PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets the RPS quantity and diversity requirements within the RCT in 2014 and 2015. PNM's proposed procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of an existing 100 MW wind energy center beginning January 1, 2015 at a first year cost of $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. PNM's plan also requests approval to increase its renewable energy rider rate to $0.0044391 per kWh effective January 1, 2014. The NMPRC is required to approve or modify the plan within 180 days of the filing date. PNM cannot predict the outcome of this proceeding. PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. Renewable Energy Rider On August 14, 2012, the NMPRC authorized PNM to recover certain renewable procurement costs through a rate rider on a per KWh basis. The approved rates are $0.0022335 per KWh in 2012 and $0.0028371 per KWh in 2013. The order disapproved the recovery of the cost of a supplemental REC procurement ordered by the NMPRC in the 2012 procurement plan case because the NMPRC had not yet acted on the specific $0.9 million procurement proposed by PNM, which is discussed under Renewable Portfolio Standard above. The NMPRC subsequently approved the supplemental REC procurement, but ordered that a hearing be held on its inclusion in the rider. Upon NMPRC approval, PNM implemented the rider on August 20, 2012. The rider will terminate upon a final order in PNM's next general rate case unless the NMPRC authorizes PNM to continue it. Amounts collected under the rider are capped at $18.0 million in 2012 and $24.6 million in 2013. Any amounts above the caps are deferred for future recovery without carrying costs. As a separate component of the rider, if PNM's earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM must refund to customers during May through December 2014 the amount over 10.5%. In compliance with the NMPRC's rate rider order, PNM filed a notice to implement an increase in the current rider rate effective with May 2013 bills. The NMPRC suspended the effective date of the new rate for a period of nine months from April 1, 2013 and appointed a Hearing Examiner to conduct a hearing on the proposed change. On May 15, 2013, the NMPRC approved the requested increase. PNM implemented the new rate of $0.030468 per KWh on May 28, 2013. Energy Efficiency and Load Management Program Costs Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. Costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of a utility's annual revenue. In October 2012, PNM filed an energy efficiency program application for programs to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive of $4.2 million and requested that the NMPRC issue an order by April 1, 2013. Portions of the program plan and proposed profit incentive are opposed by other parties to the case. PNM subsequently revised its proposed profit incentive to $2.9 million. After a hearing held in February 2013, the Hearing Examiner recommended approval of the programs as proposed and recommended an annual incentive of $1.7 million. The NMPRC has not yet acted on the Hearing Examiner's recommendations. PNM is not able to predict the outcome of this matter. Disincentives/Incentives Adder The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. A rule approved by the NMPRC authorized electric utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per KW for demand savings related to energy efficiency and demand response programs beginning in 2010. The NMAG and NMIEC appealed the NMPRC order adopting this rule to the New Mexico Supreme Court. PNM began implementing a rate rider under the rule to collect adders related to its 2010 program savings in December 2010 while the appeal of the rule was pending. In July 2011, the Supreme Court annulled and vacated the order adopting the rule and remanded the matter to the NMPRC. As a result of the Supreme Court decision, PNM filed revised tariffs and ceased collecting this adder for 2010 program savings on August 21, 2011. Of the $4.2 million authorized for recovery, $2.6 million was collected through August 20, 2011. In June 2011, prior to the Supreme Court decision, the NMPRC approved PNM-specific adders of $0.002 per KWh and $4 per KW for savings due to programs implemented in 2011. PNM is presently collecting $1.3 million in adder revenues consistent with this order. After the Supreme Court decision vacating the rule, the NMPRC initiated a proceeding to determine whether PNM should be required to cease collecting the adders and to refund all adder revenues collected since December 2010. In November 2011, the NMPRC issued orders that PNM is not required to refund any adder revenues and is authorized to continue collecting the adders. However, in an order on rehearing, which it subsequently rescinded, the NMPRC further reduced the amount of the authorized adders. Prior to the rescission, PNM appealed the rehearing order to the Supreme Court. In March 2012, the Supreme Court granted PNM's motion to vacate the rehearing order and dismiss PNM's appeal. In a separate appeal and writ proceeding in the Supreme Court, NMIEC and the NMAG seek to overturn the NMPRC order allowing PNM to continue to collect adders in light of the 2011 Supreme Court decision. On May 21, 2012 the Supreme Court dismissed the writ proceeding. Oral argument in the appeal was held in December 2012, and a decision in the appeal is expected in 2013. PNM is unable to predict the outcome of the appeal. On March 27, 2013, PNM filed its reconciliation for actual energy efficiency program costs, associated incentives, and actual collections for calendar year 2012. The reconciliation filing showed a net over-recovery of $0.2 million, composed of an over-recovery of $1.0 million of program costs and an under-recovery of incentives of $0.8 million. PNM subsequently revised the estimated incentive under-recovery to $0.5 million. PNM and the NMPRC staff filed a motion seeking to substitute the new reconciliation filing with a proposed effective date of May 28, 2013. On April 24, 2013, the NMPRC issued an order granting the motion. PNM implemented the new rate on May 28, 2013. Decoupling Rulemaking On May 15, 2012, the NMPRC issued a NOPR that would have amended the NMPRC's energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service from the rates charged on a per KWh of consumption, as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter. 2010 Electric Rate Case and FPPAC An order of the NMPRC approving an amended stipulation in PNM's 2010 Electric Rate Case limits the amount that can be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during certain years. Costs in excess of the limits are deferred, without carrying costs, for recovery in future periods. The fuel cost caps are $38.8 million for the FPPAC year beginning July 1, 2012, which PNM began collecting at that time, and $36.2 million for the FPPAC year beginning July 1, 2013. PNM estimates that the caps will result in approximately $49.6 million of FPPAC costs being deferred for future collection at June 30, 2014. Costs attributed to the mine fire incident discussed in Note 9 are included in the FPPAC amounts. Possible recovery of costs through SJCC's insurance, also discussed in Note 9, is not reflected in the FPPAC amounts. Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to either over or under-collections in the balancing account. A hearing has been scheduled to begin on December 10, 2013. PNM is unable to predict the outcome of this proceeding. 2011 Integrated Resource Plan NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. In its most recent IRP, which was filed in July 2011, PNM indicated that it planned to meet its anticipated load growth through a combination of new natural gas-fired generating plants, renewable energy resources, load management, and energy efficiency programs. As required by NMPRC rules, PNM utilized a public advisory group process during the development of the 2011 IRP. Two protests were filed to the IRP requesting rejection of the plan. The NMPRC assigned the case to a Hearing Examiner and designated a mediator to facilitate negotiations. The NMPRC staff filed a motion in December 2011 to dismiss the protests and terminate the proceeding on the ground that PNM's IRP fully complies with NMPRC rules. PNM is unable to predict the outcome of this matter. Emergency FPPAC In 2008, the NMPRC authorized PNM to implement an Emergency FPPAC from June 2, 2008 through June 30, 2009. The NMPRC order approving the Emergency FPPAC also provided that if PNM's base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM's motion and recommended that PNM be required to refund the amount collected. Auditors selected by the NMPRC found that PNM was prudent in operating its base load units and in securing replacement power but had not obtained prior NMPRC approval in the manner required by the NMPRC order. PNM continues to assert that its recovery of replacement power costs was proper and did not violate the NMPRC's order. The NMPRC has not ruled on this matter. Under the terms of the approved stipulation in the 2010 Electric Rate Case, the parties to the stipulation, including the NMPRC staff, jointly requested that the NMPRC take no further action in this matter and close the docket. No party has opposed that request. Although the NMPRC has not acted on the joint request, the NMPRC electronic docket shows the docket closed. PNM is unable to predict the outcome of this matter. Applications for Approvals to Purchase Delta As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2012 Annual Reports on Form 10-K, PNM has entered in to an agreement to purchase Delta, a 132 MW natural gas peaking unit from which PNM currently acquires energy and capacity under a PPA. The agreement to purchase Delta is subject to approvals by the NMPRC and FERC. On January 3, 2013, PNM filed an application with the NMPRC for a CCN to own and operate Delta and for a determination of related ratemaking principles and treatment. On June 26, 2013, the NMPRC granted PNM's CCN application and approved PNM's proposed ratemaking treatment. PNM filed an application for approval of the Delta acquisition at FERC on January 24, 2013. FERC approved the purchase on February 26, 2013. Closing on the purchase is anticipated before the end of 2013. Application for Approval of La Luz Generating Station On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requests a determination of related ratemaking principles and treatment. The facility is expected to cost approximately $63.2 million and go into service in the first quarter of 2016. PNM has entered into a contract for the turbine to be used for this project. PNM also has entered into a turn-key contract with an outside contractor for the construction of the generating facility. Both of these contracts allow PNM to cancel the project if NMPRC approval is not obtained. A hearing on PNM's application is scheduled to begin on April 8, 2014. PNM is unable to predict the outcome of this matter. Transmission Rate Case In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. The filing also sought to revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms. In December 2010, FERC issued an order accepting PNM's filing and suspending the proposed tariff revisions for five months. The proposed rates were implemented on June 1, 2011, subject to refund. The rate increase applied to all of PNM's wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM's transmission system to transmit power at the wholesale level. The rate increase did not impact PNM's retail customers. On January 2, 2013, FERC approved an unopposed settlement agreement, which increases transmission service revenues by $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC's approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM refunded amounts collected in excess of the settled rates in January 2013 concluding this matter. Formula Transmission Rate Case On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM's annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. The rates resulting from PNM's application are intended to replace the rates approved by the FERC on January 2, 2013 in the transmission rate case discussed above. As filed, PNM's request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM's 2011 data and a 10.81% return on equity, and authority to adjust transmission rates annually based on an approved formula. The proposed $3.2 million rate increase would be in addition to the $2.9 million rate increase approved by the FERC on January 2, 2013. On March 1, 2013, FERC issued an order (1) accepting PNM's revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its return-on-equity (“ROE”) using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM's 60% ownership of the EIP transmission line, which was acquired in 2003 ; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC's order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates will apply to all of PNM's wholesale electric transmission service customers. The new rates will not apply to PNM's retail customers. On June 10, 2013, FERC denied PNM's motion for rehearing regarding FERC's order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding. Tri-State Complaint On March 13, 2013, Tri-State filed a complaint with FERC alleging that PNM's existing transmission rates approved by FERC on January 2, 2013 in the transmission rate case discussed above are unjust and unreasonable under the Federal Power Act. Tri-State's allegations were premised upon FERC's March 1, 2013 order and certain data provided by PNM in PNM's Formula Transmission Rate Case discussed above. Tri-State sought a reduction in PNM's annual transmission revenue requirement for the period between March 13, 2013 and the implementation of PNM's proposed rates under the Formula Transmission Rate Case. Tri-State also requested that FERC consolidate the complaint proceeding with the Formula Transmission Rate Case. On April 2, 2013, PNM answered Tri-State's complaint, asking FERC to dismiss the complaint and deny Tri-State's request to consolidate the complaint proceeding with the Formula Transmission Rate Case. On June 10, 2013, FERC dismissed Tri-State's complaint and denied Tri-State's request to consolidate the complaint proceeding with the PNM FERC Transmission Formula Rate Case. This matter is now concluded. Firm-Requirements Wholesale Customers Navopache Electric Cooperative, Inc. Rate Case In September 2011, PNM filed an unexecuted amended sales agreement between PNM and NEC with FERC. The agreement proposed a cost of service based rate for the electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million or a 39.8% increase over existing rates. PNM also requested a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. NEC filed a protest to PNM's filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and PNM filed for the necessary FERC approval on December 6, 2012. The settlement agreement would result in an annual increase of $5.3 million, an extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. On April 5, 2013, FERC approved the settlement agreement. PNM has refunded the amounts collected in excess of the settled rates concluding this matter. City of Gallup, New Mexico Contract Approval Case PNM provides both energy and power services to Gallup, PNM's second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement. Revenue from Gallup will increase by $3.1 million during the term of the amended agreement. PNM is unable to predict if services provided to Gallup will continue upon expiration of the amended agreement. TNMP Advanced Meter System Deployment and Surcharge Request In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period. In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT has requested comments and convened a public meeting to hear various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012. On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. A hearing to receive additional comment on the proposed rulemaking was held on April 19, 2013. Any opt-out program would apply to all transmission and distribution utilities in ERCOT. TNMP cannot predict the outcome or effect of this proceeding. Energy Efficiency TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor. On August 28, 2012, the PUCT approved a settlement that permits TNMP to collect estimated 2013 program costs of $4.8 million, plus recovery of an aggregate of $0.4 million in under-collected costs from prior years, case expenses, and a performance bonus for 2011. TNMP's new rates were effective January 1, 2013. On May 15, 2013, TNMP filed its 2014 energy efficiency cost recovery factor application with the PUCT. The application seeks approval to collect $5.6 million, which includes $4.7 million in estimated program expenses for 2014, a $0.7 million performance bonus for 2012, a refund of $0.1 million over collection of energy savings expenses for the 2012 program year, and case expenses. In July 2013, the parties filed a settlement to resolve this proceeding, which would permit TNMP to collect the substantially all of the requested $5.6 million. The settlement is subject to the PUCT's review and approval. TNMP cannot predict the outcome of this matter. Transmission Cost of Service Rates TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. On January 31, 2013, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base was $21.9 million, which would increase revenues $2.9 million annually. On March 19, 2013, the PUCT ALJ approved TNMP's interim transmission cost of service filing and rates went into effect with bills rendered March 20, 2013. |
Regulatory and Rate Matters (Details) (USD $)
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Emergency FPPAC [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
La Luz Generating Station [Member]
MW
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Dec. 31, 2011
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
MW
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Minimum [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Maximum [Member]
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Mar. 31, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Maximum [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Wind Energy [Member]
Minimum [Member]
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Dec. 31, 2012
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Wind Energy [Member]
Minimum [Member]
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Dec. 31, 2012
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Solar Energy [Member]
Minimum [Member]
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Sep. 30, 2012
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Solar Energy [Member]
Minimum [Member]
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Dec. 31, 2012
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Renewable Technologies [Member]
Minimum [Member]
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Sep. 30, 2012
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Renewable Technologies [Member]
Minimum [Member]
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Dec. 31, 2012
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Distributed Generation [Member]
Minimum [Member]
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Sep. 30, 2012
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Distributed Generation [Member]
Minimum [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Required Percentage by 2011 [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Required Percentage by 2015 [Member]
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Mar. 31, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Required Percentage by 2015 [Member]
Distributed Generation [Member]
Minimum [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard [Member]
Required Percentage by 2020 [Member]
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard Supplemental Procurement [Member]
MW
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Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard Supplemental Procurement Reduction [Member]
Minimum [Member]
MW
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard Supplemental Procurement Reduction [Member]
Maximum [Member]
MW
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
2014 Wind generated Renewable Energy Credits [Member]
MWh
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard 2014 [Member]
MW
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Portfolio Standard 2014 [Member]
MW
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
2015 Wind generated Renewable Energy Credits [Member]
MWh
|
Aug. 20, 2011
Public Service Company of New Mexico [Member]
NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]
|
Nov. 29, 2010
Public Service Company of New Mexico [Member]
NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]
|
May 03, 2010
Public Service Company of New Mexico [Member]
NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]
Per KWh [Member]
Maximum [Member]
|
May 03, 2010
Public Service Company of New Mexico [Member]
NMPRC Rulemaking on Disincentives to Energy Efficiency Programs [Member]
Per kilowatt [Member]
|
Oct. 05, 2012
Public Service Company of New Mexico [Member]
2010 Energy Efficiency Application [Member]
Disincentives / Incentives Adder [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
2010 Energy Efficiency Application [Member]
Disincentives / Incentives Adder [Member]
|
Aug. 11, 2011
Public Service Company of New Mexico [Member]
2010 Energy Efficiency Application [Member]
Disincentives / Incentives Adder [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
2010 Energy Efficiency Application [Member]
Per KWh [Member]
Amended [Member]
Minimum [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
2010 Energy Efficiency Application [Member]
Per kilowatt [Member]
Amended [Member]
Minimum [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
2010 Electric Rate Case [Member]
|
Mar. 31, 2013
Public Service Company of New Mexico [Member]
2010 Electric Rate Case [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Energy Rider [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Energy Rider [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Energy Rider [Member]
Maximum [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Renewable Energy Rider [Member]
Maximum [Member]
|
Dec. 31, 2012
Public Service Company of New Mexico [Member]
Renewable Energy Rider [Member]
Maximum [Member]
|
Jul. 31, 2011
Public Service Company of New Mexico [Member]
Integrated Resource Plan, 2011 [Member]
Protests_Filed
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Integrated Resource Plan, 2011 [Member]
|
Jul. 03, 2012
Public Service Company of New Mexico [Member]
Transmission Rate Case [Member]
|
Oct. 27, 2010
Public Service Company of New Mexico [Member]
Transmission Rate Case [Member]
|
Jul. 26, 2013
Public Service Company of New Mexico [Member]
Formula Transmission Rate Case [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
Formula Transmission Rate Case [Member]
|
Jan. 02, 2013
Public Service Company of New Mexico [Member]
Formula Transmission Rate Case [Member]
|
Dec. 06, 2012
Public Service Company of New Mexico [Member]
Firm Requirements Wholesale Power Rate Case [Member]
|
Sep. 15, 2011
Public Service Company of New Mexico [Member]
Firm Requirements Wholesale Power Rate Case [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
City of Gallup, New Mexico Contract [Member]
|
Jul. 31, 2011
Texas-New Mexico Power Company [Member]
Advanced Meter System Deployment and Surcharge Request [Member]
|
Aug. 28, 2012
Texas-New Mexico Power Company [Member]
Energy Efficiency [Member]
|
Jun. 30, 2013
Texas-New Mexico Power Company [Member]
Energy Efficiency [Member]
|
Jan. 31, 2013
Texas-New Mexico Power Company [Member]
Transmission Rate Filings [Member]
|
Jun. 30, 2013
Texas-New Mexico Power Company [Member]
August 2013 Transmission Rate Filings [Member]
|
Jun. 30, 2013
Delta [Member]
Public Service Company of New Mexico [Member]
Applications for Approvals to Purchase Delta [Member]
MW
|
|
Rate Matters [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Required Percentage of Renewable Energy in Portfolio to Electric Sales | 10.00% | 15.00% | 20.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Required Percentage of Diversification | 20.00% | 30.00% | 20.00% | 20.00% | 5.00% | 10.00% | 1.50% | 1.50% | 3.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Reasonable Cost Threshold | 2.00% | 3.00% | 3.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Annual Incremental Increase in Reasonable Cost Threshold | 0.25% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilites, Additional Renewable Procurements Spending Required by NMPRC | $ 900,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Number of Mega Watts of Solar PV Capacity | 20 | 2 | 1.5 | 2 | 23 | 23 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Number of Mega Watts of Wind Energy Capcity | 100 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, First Year Cost of Wind Capacity Planned Purchase Agreement | 5,800,000.0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Number of Mega Watt Hours of Wind Generation | 50,000 | 120,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Requested Rider Rate For 2014 | 0.0044391 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Estimated Cost of Mega Watts of Solar PV Capacity | 45,500,000 | 4,500,000 | 46,700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Number of Mega Watts of Geothermal Capacity | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Wind Capacity Planned Purchase Agreement Term | 20 years | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Program Costs Related To Energy Efficiency | 22,500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Proposed Profit Incentive Adder Revenues Related To Energy Efficiency Program | 4,200,000 | 2,900,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rate Adder Allowed | 0.01 | 10 | 0.002 | 4 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rate Rider Recovered | 2,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Regulatory Costs Approved | 4,200,000 | 2,900,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage ownership of EIP transmission line | 60.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Eliminated Recovery of Adder Revenue | 1,300,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rate Rider Net Over-Recovery | 200,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rate Rider Program Costs Over-Recovery | 1,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rate Rider Incentives Under-Recovery | 800,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rate Rider Estimated Incentives Under-Recovery | 500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Regulatory Costs to be Collected | 36,200,000 | 38,800,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Regulatory Costs Incurred and Eligible For Recovery, Amount Deferred for Collection in Future Period | 49,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Additional Revenue To be Collected in 2012 | 18,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Additional Revenue To be Collected in 2013 | 24,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rider Condition of Earned Return on Jurisdictional Equity in 2013 | 10.50% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Rate Rider to be Implemented | 0.030468 | 0.030468 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Approved Rider Rate For 2012 | 0.0022335 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Approved Rider Rate For 2013 | 0.0028371 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Order Disapproved Recovery of Costs As Regulatory Agency Had Not Acted on Specific Procurements Proposed | 900,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Planning Period Covered of IRP | 20 years | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Number of protests that were filed to IRP requesting rejection of the plan | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount of Regulatory Costs Not yet Approved | 8,000,000 | 11,100,000 | 1,300,000 | 3,200,000 | 8,700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilites, Number of Mega Watts Natural Gas Peaking Units to be Purchased | 132 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Number of Mega Watts of Gas-fired Generation | 40 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Installation Capital Costs | 63,200,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Return on Equity | 0.1225 | 0.1081 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Regulatory Rate Increase | 0.398 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Collection of Deployment Costs Through Surcharge Period | 12 years | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Completion Period of Advanced Meter Deployment | 5 years | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Increase Annual Transmission Service Revenue | 2,900,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Additional Revenue from Proposed Rates | 21,900,000 | 18,100,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Total Revenue Requirement Increase | 5,300,000 | 2,900,000 | 2,800,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Contract Extension | 10 years | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Estimated Increase in Revenue over amendment term | 3,100,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Approved Deployment Costs | 113,300,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Approved Program Implementation Costs | 4,800,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Approved Program Implementation Costs, Bonus | 400,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Unapproved 2014 Program Implementation Costs | 5,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Unapproved 2014 Program Implementation Costs, Expense | 4,700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Unapproved 2014 Program Implementation Costs, Bonus | 700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Unapproved 2014 Program Implementation Costs, Overcollection refund | $ 100,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Retention Percentage of Sales Margins | 10.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, Frequency of IRP filings | P3Y |
Earnings Per Share (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | Information regarding the computation of earnings per share is as follows:
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Fair Value of Derivative and Other Financial Instruments (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Fair Value of Derivative and Other Financial Instruments [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value, by Balance Sheet Grouping [Table Text Block] | The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:
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PNMR and PNM [Member]
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Fair Value of Derivative and Other Financial Instruments [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:
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Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block] | The following table presents the effect on earnings, excluding income tax effects, of commodity derivative instruments that are recorded at fair value. Commodity derivatives had no impact on OCI for the periods presented.
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Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block] | Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:
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Schedule of Collateral Related to Derivative [Table Text Block] | Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.
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Available-for-sale Securities [Table Text Block] | The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold.
The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.
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Investments Classified by Contractual Maturity Date [Table Text Block] | At June 30, 2013, the available-for-sale and held-to-maturity debt securities had the following final maturities:
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Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Table Text Block] | Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:
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Commitments and Contingencies (Commitments and Contingencies Related to the Environment) (Details) (USD $)
In Millions, unless otherwise specified |
12 Months Ended | 12 Months Ended | 6 Months Ended | |||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 21, 2011
mw
|
Dec. 21, 2011
San Juan Generating Station [Member]
|
Oct. 31, 2012
San Juan Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
San Juan Generating Station Units 1 and 4 [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
San Juan Generating Station Units 2 and 3 [Member]
PNM [Member]
|
Nov. 08, 2010
Four Corners [Member]
|
Jun. 30, 2013
Clean Air Act related to Regional Haze [Member]
state
|
Jun. 30, 2013
Clean Air Act Related to Post Combustion Controls [Member]
Four Corners [Member]
Public Service Company of New Mexico [Member]
|
Aug. 06, 2012
Clean Air Act Related to Post Combustion Controls [Member]
Four Corners [Member]
Public Service Company of New Mexico [Member]
compliance_alternative
|
Sep. 30, 2012
Mercury Control [Member]
San Juan Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Jan. 31, 2010
Minimum [Member]
San Juan Generating Station And Four Corners [Member]
Public Service Company of New Mexico [Member]
opp
|
Jan. 31, 2010
Maximum [Member]
San Juan Generating Station And Four Corners [Member]
Public Service Company of New Mexico [Member]
opp
|
Sep. 30, 2012
Maximum [Member]
Mercury Control [Member]
San Juan Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Oct. 31, 2012
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]
Minimum [Member]
Clean Air Act, SNCR [Member]
San Juan Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]
Minimum [Member]
Clean Air Act, SNCR [Member]
San Juan Generating Station Units 1 and 4 [Member]
Public Service Company of New Mexico [Member]
|
Oct. 31, 2012
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]
Maximum [Member]
Clean Air Act, SNCR [Member]
San Juan Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Installation Costs Including Construction Management, Gross Receipts Taxes, AFUDC, and Other PNM Costs [Member]
Maximum [Member]
Clean Air Act, SNCR [Member]
San Juan Generating Station Units 1 and 4 [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Environmental Protection Agency [Member]
WildEarth Guardians filed an action to challenge EPA's rule in the Tenth Circuit [Member]
San Juan Generating Station [Member]
|
Jun. 30, 2013
Environmental Protection Agency [Member]
Clean Air Act Related to Post Combustion Controls [Member]
Four Corners [Member]
Public Service Company of New Mexico [Member]
|
Dec. 31, 2012
Nuclear Spent Fuel And Waste Disposal [Member]
Palo Verde Nuclear Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Nuclear Spent Fuel And Waste Disposal [Member]
Other Deferred Credits [Member]
Palo Verde Nuclear Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Dec. 31, 2012
Nuclear Spent Fuel And Waste Disposal [Member]
Other Deferred Credits [Member]
Palo Verde Nuclear Generating Station [Member]
Public Service Company of New Mexico [Member]
|
|
Public Utilities, Commitments and Contingencies [Line Items] | ||||||||||||||||||||||
Loss Contingency, Estimate of Possible Loss | $ 75.0 | $ 42.8 | ||||||||||||||||||||
Public Utilities, Number of Compliance alternatives | 2 | |||||||||||||||||||||
Public Utilities, Number of States To Address Regional Haze | 50 | |||||||||||||||||||||
Public Utilities, Potential to emit tons per year of visibility impairing pollution, maximum | 250 | |||||||||||||||||||||
Estimated Total Capital Cost If Requirement Occured | 824 | 910 | ||||||||||||||||||||
Estimated Installation Capital Costs | 85.0 | 60.0 | 90.0 | 80.0 | ||||||||||||||||||
Estimated Portion of Total Capital Costs if Requirement Occured | 105 | 110 | ||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 46.30% | 52.00% | ||||||||||||||||||||
estimated cost of replacing gas fired peaking capacity due to retirement of SJGS units | 280 | |||||||||||||||||||||
Net book value | 289 | |||||||||||||||||||||
Public Utilities, Government Standard Emission Limit | 0.060 | 0.070 | ||||||||||||||||||||
Public Utilitites, Plant Requirment to Meet Opacity Limit, Percentage | 20.00% | |||||||||||||||||||||
Public Utilities, Rule Imposes Opacity Limitation on Certain Fugitive Dust Emissions From Coal and Material Handling Operations | 20.00% | |||||||||||||||||||||
Current Annual Mercury Control Costs | 0.6 | |||||||||||||||||||||
Contingent Estimated Annual Mercury Control Cost | 6.1 | |||||||||||||||||||||
Minimum Megawatt Capacity from Coal and Oil-Fired Electric Generating Units under Jurisdiction of the Merucy and Air Toxics Standards | 25 | |||||||||||||||||||||
Mercury Removal Rate, Percentage | 0.99 | |||||||||||||||||||||
Public Utilities, Proposed Seeking Shorter Compliance Period | 5 years | |||||||||||||||||||||
Public Utilities, Number of years after issuance of final determination to achieve compliance with requirements | 3 years | |||||||||||||||||||||
Loss Contingency Accrual, at Carrying Value | $ 12.3 | $ 13.9 | ||||||||||||||||||||
Public Utilties, Jointly Owned Utility Plant, Sale of Ownership Percentage | 48.00% |
Variable Interest Entities (Details) (USD $)
|
3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
Mar. 31, 2013
|
Dec. 31, 2012
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
|
Jun. 30, 2012
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Public Service Company of New Mexico [Member]
|
Jun. 30, 2012
Public Service Company of New Mexico [Member]
|
Mar. 31, 2013
Public Service Company of New Mexico [Member]
|
Dec. 31, 2012
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Valencia [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2012
Valencia [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Valencia [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2012
Valencia [Member]
Public Service Company of New Mexico [Member]
|
Dec. 31, 2012
Valencia [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Delta [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Delta [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Palo Verde Nuclear Generating Station [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Palo Verde Nuclear Generating Station [Member]
Property Lease Guarantee [Member]
Maximum [Member]
Public Service Company of New Mexico [Member]
|
May 30, 2008
Purchased Through May 30, 2028 [Member]
Valencia [Member]
Public Service Company of New Mexico [Member]
MW
|
Jun. 30, 2013
Delta [Member]
Public Service Company of New Mexico [Member]
|
Mar. 31, 2013
Delta [Member]
Public Service Company of New Mexico [Member]
|
Jun. 30, 2013
Delta [Member]
Public Service Company of New Mexico [Member]
|
Dec. 31, 2012
Delta [Member]
Public Service Company of New Mexico [Member]
|
|
Variable Interest Entity [Line Items] | ||||||||||||||||||||||||||
Number of mega watts purchased (in megawatts) | 145 | |||||||||||||||||||||||||
Long Term Contract For Purchase of Electric Power Fixed Costs | $ 4,700,000 | $ 4,600,000 | $ 9,400,000 | $ 9,300,000 | $ 1,600,000 | $ 3,200,000 | ||||||||||||||||||||
Long Term Contract For Purchase of Electric Power Variable Charges | 200,000 | 300,000 | 300,000 | 400,000 | 600,000 | |||||||||||||||||||||
Variable Interest Entity, Statement Of Operation [Abstract] | ||||||||||||||||||||||||||
Operating revenues | 4,922,000 | 4,888,000 | 9,697,000 | 9,559,000 | ||||||||||||||||||||||
Operating expenses | (1,349,000) | (1,433,000) | (2,920,000) | (2,839,000) | ||||||||||||||||||||||
Earnings Attributable to non-controlling interest | 3,573,000 | 3,455,000 | 6,777,000 | 6,720,000 | 3,573,000 | 3,455,000 | 6,777,000 | 6,720,000 | 3,573,000 | 3,455,000 | 6,777,000 | 6,720,000 | ||||||||||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets and Liabilities, Net [Abstract] | ||||||||||||||||||||||||||
Current assets | 393,157,000 | 393,157,000 | 442,191,000 | 384,105,000 | 384,105,000 | 387,689,000 | 3,124,000 | 3,124,000 | 3,655,000 | |||||||||||||||||
Net property, plant and equipment | 76,541,000 | 76,541,000 | 77,953,000 | |||||||||||||||||||||||
Assets | 5,403,906,000 | 5,252,589,000 | 5,403,906,000 | 5,252,589,000 | 5,372,583,000 | 4,185,189,000 | 4,185,189,000 | 4,163,907,000 | 79,665,000 | 79,665,000 | 81,608,000 | |||||||||||||||
Current liabilities | 444,590,000 | 434,103,000 | 196,239,000 | 242,751,000 | 720,000 | 720,000 | 765,000 | |||||||||||||||||||
Owners' equity - non-controlling interest | 78,945,000 | 80,843,000 | 78,945,000 | 80,843,000 | 78,945,000 | 78,945,000 | 80,843,000 | |||||||||||||||||||
Operating Leases, Fixed Rate Percentage of Renewal Options After Original Lease Term | 50.00% | |||||||||||||||||||||||||
Operating Leases, Renewal Options After Original Lease Term (in years) | 2 years | |||||||||||||||||||||||||
Operating Lease, Percentage of Unit 2 Capacity That May Be Extended | 14.00% | |||||||||||||||||||||||||
Operating Leases, Extended Lease Term Option (in years) | 6 years | |||||||||||||||||||||||||
Operating Leases, Future Minimum Payments Due | 65,900,000 | |||||||||||||||||||||||||
Loss Contingency, Range of Possible Loss, Portion Not Accrued | 160,400,000 | |||||||||||||||||||||||||
Operating Leases, Future Minimum Payments Due, Next Six Months | 26,000,000 | |||||||||||||||||||||||||
Long Term Contract for Purchase of Electric Power Aggregate Amount of Contract Remaining | 42,200,000 | 42,200,000 | ||||||||||||||||||||||||
Payments to Acquire Businesses, Gross | 23,000,000 | |||||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt | 17,700,000 | 17,700,000 | ||||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt | 3,200,000 | 3,200,000 | ||||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 25,400,000 | 25,400,000 | ||||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 21,700,000 | 21,700,000 | ||||||||||||||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | 19,600,000 | 19,600,000 | ||||||||||||||||||||||||
Revenues | 2,200,000 | 4,000,000 | ||||||||||||||||||||||||
Net Earnings | $ 27,678,000 | $ 21,512,000 | $ 38,304,000 | $ 38,592,000 | $ 26,124,000 | $ 16,885,000 | $ 37,693,000 | $ 34,697,000 | $ 100,000 | $ 300,000 |
Related Party Transactions (Details) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
|
Service billings [Member] | TNMP to PNMR [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 2 | $ 4 | $ 4 | $ 8 |
Service billings [Member] | PNMR to PNM [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 20,837 | 23,832 | 43,489 | 45,887 |
Service billings [Member] | PNMR to TNMP [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 6,856 | 6,816 | 14,217 | 13,767 |
Service billings [Member] | PNM to TNMP [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 133 | 168 | 241 | 289 |
Interest charges [Member] | PNMR to PNM [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 0 | 1 | 1 | 1 |
Interest charges [Member] | PNMR to TNMP [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 119 | 32 | 215 | 50 |
Interest charges [Member] | PNM to PNMR [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 37 | 44 | 78 | 89 |
Income tax sharing payments [Member] | PNMR to PNM [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | 45,000 | 0 | 45,000 | 63,114 |
Income tax sharing payments [Member] | PNMR to TNMP [Member]
|
||||
Related Party Transaction [Line Items] | ||||
Amount of related party transaction | $ 0 | $ 0 | $ 0 | $ 1,952 |
Related Party Transactions (Tables)
|
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Related Party Transactions [Table Text Block] | The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:
|
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