x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Incorporated in South Dakota | 625 Ninth Street | IRS Identification Number |
Rapid City, South Dakota 57701 | 46-0458824 | |
Registrant's telephone number, including area code (605) 721-1700 | ||
Securities registered pursuant to Section 12(b) of the Act: | ||
Title of each class | Name of each exchange on which registered | |
Common stock of $1.00 par value | New York Stock Exchange |
Large accelerated filer x | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
Class | Outstanding at January 31, 2012 | ||
Common stock, $1.00 par value | 43,929,272 | shares |
Page | ||||
GLOSSARY OF TERMS AND ABBREVIATIONS | ||||
ACCOUNTING PRONOUNCEMENTS | ||||
WEBSITE ACCESS TO REPORTS | ||||
FORWARD-LOOKING INFORMATION | ||||
Part I | ||||
ITEMS 1. and 2. | BUSINESS AND PROPERTIES | |||
ITEM 1A. | RISK FACTORS | |||
ITEM 1B. | UNRESOLVED STAFF COMMENTS | |||
ITEM 3. | LEGAL PROCEEDINGS | |||
ITEM 4. | SPECIALIZED DISCLOSURES | |||
Part II | ||||
ITEM 5. | MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | |||
ITEM 6. | SELECTED FINANCIAL DATA | |||
ITEMS 7. and 7A. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | |||
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | |||
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | |||
ITEM 9A. | CONTROLS AND PROCEDURES | |||
ITEM 9B. | OTHER INFORMATION | |||
Part III | ||||
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | |||
ITEM 11. | EXECUTIVE COMPENSATION | |||
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | |||
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | |||
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES | |||
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | |||
SIGNATURES | ||||
INDEX TO EXHIBITS |
AFUDC | Allowance for Funds Used During Construction |
AOCI | Accumulated Other Comprehensive Income |
Aquila | Aquila, Inc. |
Aquila Transaction | Our July 14, 2008 acquisition of five utilities from Aquila |
ARO | Asset Retirement Obligations |
Basin Electric | Basin Electric Power Cooperative |
Bbl | Barrel |
Bcf | Billion cubic feet |
Bcfe | Billion cubic feet equivalent |
BHC | Black Hills Corporation; the Company |
BHCCP | Black Hills Corporation Credit Policy |
BHCRPP | Black Hills Corporation Risk Policies and Procedures |
BHEP | Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
Black Hills Colorado IPP | Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation |
Black Hills Energy | The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries |
Black Hills Electric Generation | Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
Black Hills Non-regulated Holdings | Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation |
Black Hills Power | Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation |
Black Hills Utility Holdings | Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation |
Black Hills Wyoming | Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation |
BLM | United States Bureau of Land Management |
Btu | British thermal unit |
CFTC | United States Commodity Futures Trading Commission |
CG&A | Cawley, Gillespie & Associates, Inc., an independent consulting and engineering firm |
Cheyenne Light | Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation |
Cheyenne Light Pension Plan | The Cheyenne Light, Fuel and Power Company Pension Plan |
City of Gillette | The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase of 23% of Wygen III power plant for the City of Gillette |
CO2 | Carbon dioxide |
Colorado Electric | Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings |
Colorado Gas | Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings |
Cooling Degree Day | A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average. |
CPCN | Certificate of Public Convenience and Necessity |
CPUC | Colorado Public Utilities Commission |
CT | Combustion turbine |
DC | Direct current |
De-designated interest rate swaps | The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under the accounting for derivatives and hedges but subsequently de-designated in December 2008 |
Dodd-Frank | Dodd-Frank Wall Street Reform and Consumer Protection Act |
DOE | United States Department of Energy |
Dth | Dekatherms |
EBITDA | Earnings before interest, taxes, depreciation and amortization, a Non-GAAP measurement |
ECA | Energy Cost Adjustment |
Enserco | Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-regulated Holdings, which is presented in discontinued operations throughout this Annual Report filed on Form 10-K |
EPA | United States Environmental Protection Agency |
EPA Region VIII | EPA Region VIII (Mountains and Plains) located in Denver, Colorado serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations |
Equity Forward Agreement | Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,413,519 million shares of Black Hills Corporation common stock, including the over-allotment shares |
ERISA | Employee Retirement Income Security Act |
EWG | Exempt Wholesale Generator |
FASB | Financial Accounting Standards Board |
FERC | United States Federal Energy Regulatory Commission |
Fitch | Fitch Ratings |
FTC | Federal Trade Commission |
GAAP | Accounting principles generally accepted in the United States of America |
GCA | Gas Cost Adjustment |
GE | General Electric Company |
GHG | Greenhouse gases |
Global Settlement | Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders |
Happy Jack | Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services |
Hastings | Hastings Fund Management Ltd |
Heating Degree Day | A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average. |
IGCC | Integrated Gasification Combined Cycle |
IIF | IIF BH Investment LLC, a subsidiary of an investment entity advised by J.P. Morgan Asset Management |
Iowa Gas | Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings |
IPP | Independent power producer |
IPP Transaction | The July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings and IIF |
IRS | United States Internal Revenue Service |
IUB | Iowa Utilities Board |
J.P. Morgan | J.P. Morgan Securities LLC |
JPB | Consolidated Wyoming Municipalities Electric Power System Joint Powers Board. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. |
Kansas Gas | Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings |
KCC | Kansas Corporation Commission |
kV | Kilovolt |
KW | Kilowatt |
KWh | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
LOE | Lease Operating Expense |
MACT | Maximum Achievable Control Technology |
MAPP | Mid-Continent Area Power Pool |
MATS | Utility Mercury and Air Toxics Rules under the United States EPA National Emissions Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units |
Mbbl | Thousand barrels of oil |
Mcf | Thousand cubic feet |
Mcfe | Thousand cubic feet equivalent |
MDU | Montana Dakota Utilities Co., a regulated utility division of MDU Resources Group, Inc. |
MEAN | Municipal Energy Agency of Nebraska |
MMBtu | Million British thermal units |
MMcf | Million cubic feet |
MMcfe | Million cubic feet equivalent |
Moody's | Moody's Investors Service, Inc. |
MSHA | Mine Safety and Health Administration |
MTPSC | Montana Public Service Commission |
MW | Megawatts |
MWh | Megawatt-hours |
Native load | Energy required to serve customers within our service territory |
Nebraska Gas | Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings |
NERC | North American Electric Reliability Corporation |
NGL | Natural Gas Liquids |
NOx | Nitrogen oxide |
NOL | Net operating loss |
NPA | Nebraska Power Association |
NPDES | National Pollutant Discharge Elimination System |
NPSC | Nebraska Public Service Commission |
NQDC | Non-Qualified Deferred Compensation Plan initially adopted in 1999 |
NYMEX | New York Mercantile Exchange |
OCA | Office of Consumer Advocate |
OPEC | Organization of the Petroleum Exporting Countries |
OSHA | Occupational Safety & Health Administration |
PCA | Power Cost Adjustment |
Peak demand | Peak demand represents the highest point of customer usage for a single hour |
PGA | Purchased Gas Adjustment |
PPA | Power Purchase Agreement |
PPACA | Patient Protection and Affordable Care Act of 2010 |
PSCo | Public Service Company of Colorado |
PUD | Proved undeveloped reserves |
PUHCA 2005 | Public Utility Holding Company Act of 2005 |
PURPA | Public Utility Regulatory Policies Act of 1978 |
RCRA | Resource Conservation and Recovery Act |
Revolving Credit Facility | Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, originally expiring April 14, 2013. We entered into a new facility in February 2012 which expires in 2017. |
S&S | Significant and Substantial as defined by Mine Safety Act |
SCADA | Supervisory Control and Data Acquisition |
SDPUC | South Dakota Public Utilities Commission |
SEC | U. S. Securities and Exchange Commission |
Silver Sage | Silver Sage Windpower, LLC, owned by Duke Energy Generation Services |
SO2 | Sulfur dioxide |
S&P | Standard & Poor's, a division of The McGraw-Hill Companies, Inc. |
TCA | Transmission Cost Adjustment |
Twin Eagle | Twin Eagle Resource Management, LLC |
VEBA | Voluntary Employee Benefit Association |
VIE | Variable Interest Entity |
WDEQ | Wyoming Department of Environmental Quality |
WECC | Western Electricity Coordinating Council |
WPSC | Wyoming Public Service Commission |
WRDC | Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
ASC | Accounting Standards Codification |
ASC 220 | ASC 220, "Comprehensive Income" |
ASC 820 | ASC 820, "Fair Value Measurements and Disclosures" |
ASC 932-10-S99 | ASC 932-10-S99, "Extractive Activities - Oil and Gas, SEC Materials" |
ASU | Accounting Standards Update |
ASU 2011-04 | ASU 2011-04, "Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS" |
ASU 2011-05 | ASU 2011-05, "Comprehensive Income: Presentation of Comprehensive Income" |
ASU 2011-08 | ASU 2011-08, "Intangibles - Goodwill and Other: Testing Goodwill for Impairment" |
ASU 2011-12 | ASU 2011-12, "Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05" |
IFRS | International Financial Reporting Standards |
• | Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidations and changes in competition, and (ii) general economic and political conditions, including tax rates or policies and inflation rates; |
• | The timing, volatility and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets; |
• | Our ability to comply, or to make expenditures required to comply, with changes in laws and regulations, particularly those relating to energy markets, taxation, safety and protection of the environment, and our ability to recover those expenditures in customer rates, where applicable; |
• | Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, which may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain, or which could require closure of one or more of our generating units; |
• | Changes in business, regulatory compliance and financial reporting practices and subsequent rules and regulations; |
• | The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our activities to hedge our expected production of crude oil and natural gas and on our use of interest rate derivative instruments; |
• | Changes in state laws or regulations that could cause us to curtail our business activities; |
• | Our ability to successfully integrate and profitably operate any future acquisitions; |
• | Our ability to successfully complete the sale of Enserco Energy Inc. to Twin Eagle Resource Management, LLC for net cash proceeds of approximately $160 million to $170 million, subject to working capital and other closing adjustments; |
• | Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel, transportation, transmission and purchased power in our regulated utilities; |
• | Our ability to receive regulatory approval to recover in rate base our expenditures for new power generation facilities or other utility infrastructure; |
• | Our ability to recover our borrowing costs, including debt service costs, in our customer rates; |
• | The extent of our success in connecting natural gas supplies to gathering, processing and pipeline systems; |
• | Our ability to minimize losses related to defaults on amounts due from customers and counterparties, including counterparties to trading and other commercial transactions; |
• | The timing and extent of scheduled and unscheduled outages of power generation facilities; |
• | Our ability to complete the permitting, construction, start-up and operation of power generating facilities in a cost-effective and timely manner; |
• | Our ability to accurately estimate demand from our customers for natural gas; |
• | Weather and other natural phenomena; |
• | Our ability to meet forecasted production volumes for our oil and gas properties, which may be dependent upon issuance by federal, state and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force and equipment, or the possibility of reductions in our drilling program resulting from the current economic climate and commodity prices, which also may prevent us from maintaining production rates and replacing reserves for our oil and gas properties; |
• | The amount of collateral required to be posted from time to time in our transactions; |
• | Our ability to effectively use derivative financial instruments to hedge commodity and interest rate risks; |
• | Our ability to provide accurate estimates of proved oil and gas reserves, coal reserves and future production rates and associated costs; |
• | Price risk due to marketable securities held as investments in employee benefit plans; |
• | Our ability to successfully maintain our corporate credit rating; |
• | The impact of the pending sale of Enserco Energy Inc., our non-regulated energy marketing business, on reducing our risk profile, improving our credit metrics and enhancing our ability to produce more stable cash flows and earnings; |
• | Our ability to access revolving credit capacity and comply with loan covenants; |
• | Capital market conditions and market uncertainties related to interest rates, which may affect our ability to raise capital on favorable terms; |
• | The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock; |
• | Our ability to continue paying our regular quarterly dividend; |
• | Our ability to obtain permanent financing for capital expenditures on reasonable terms either through long-term debt or issuance of equity; |
• | The effect of accounting policies issued periodically by accounting standard-setting bodies; |
• | The accounting treatment and earnings impact associated with interest rate swaps; |
• | The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge; |
• | The possibility that we may be required to take impairment charges under the SEC's full cost ceiling test for the accumulated costs of our natural gas and oil reserves; |
• | The outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements on our financial condition or results of operations; |
• | Additional liabilities for environmental conditions, including remediation and reclamation obligations, under environmental laws; |
• | Our ability to successfully complete labor negotiations with labor unions with which we have collective bargaining agreements and for which we are currently in, or are soon to be in, contract renewal negotiations; and |
• | The cost and effect on our business, including insurance, resulting from terrorist actions and cyber-attacks or responses to such actions or events. |
ITEMS 1 AND 2. | BUSINESS AND PROPERTIES |
Business Group | Financial Segment |
Utilities | Electric Utilities |
Gas Utilities | |
Non-regulated Energy | Oil and Gas |
Power Generation | |
Coal Mining |
System Peak Demand (in MW) | ||||||||||
2011 | 2010 | 2009 | ||||||||
Summer | Winter | Summer | Winter | Summer | Winter | |||||
Black Hills Power | 452 | 408 | 396 | 377 | 387 | 392 | ||||
Cheyenne Light | 181 | 175 | 176 | 164 | 169 | 171 | ||||
Colorado Electric | 392 | 297 | 384 | 289 | 365 | 296 | ||||
Total Electric Utilities Peak Demands | 1,025 | 880 | 956 | 830 | 921 | 859 |
Unit | Fuel Type | Location | Ownership Interest % | Owned/Leased Capacity (MW) | Year Installed |
Black Hills Power: | |||||
Wygen III (1) | Coal | Gillette, WY | 52.0% | 57.2 | 2010 |
Neil Simpson II | Coal | Gillette, WY | 100.0% | 90.0 | 1995 |
Wyodak (2) | Coal | Gillette, WY | 20.0% | 72.4 | 1978 |
Osage (3) | Coal | Osage, WY | 100.0% | 34.5 | 1948-1952 |
Ben French | Coal | Rapid City, SD | 100.0% | 25.0 | 1960 |
Neil Simpson I | Coal | Gillette, WY | 100.0% | 21.8 | 1969 |
Neil Simpson CT | Gas | Gillette, WY | 100.0% | 40.0 | 2000 |
Lange CT | Gas | Rapid City, SD | 100.0% | 40.0 | 2002 |
Ben French Diesel #1-5 | Oil | Rapid City, SD | 100.0% | 10.0 | 1965 |
Ben French CTs #1-4 (4) | Gas/Oil | Rapid City, SD | 100.0% | 100.0 | 1977-1979 |
Cheyenne Light: | |||||
Wygen II | Coal | Gillette, WY | 100.0% | 95.0 | 2008 |
Colorado Electric: | |||||
Pueblo Airport Generation | Gas | Pueblo, CO | 100.0% | 180.0 | 2011 |
Capital Lease - Colorado IPP (5) | Gas | Pueblo, CO | —% | 200.0 | 2011 |
W.N. Clark #1-2 (6) | Coal | Canon City, CO | 100.0% | 40.0 | 1955, 1959 |
Pueblo #6 | Gas | Pueblo, CO | 100.0% | 20.0 | 1949 |
Pueblo #5 | Gas | Pueblo, CO | 100.0% | 9.0 | 1941, 2001 |
AIP Diesel | Oil | Pueblo, CO | 100.0% | 10.0 | 2001 |
Diesel #1-5 | Oil | Pueblo, CO | 100.0% | 10.0 | 1964 |
Diesel #1-5 | Oil | Rocky Ford, CO | 100.0% | 10.0 | 1964 |
Total MW Owned Capacity | 1,064.9 |
(1) | Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power has a 52% ownership interest in Wygen III, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our WRDC coal mine furnishes all of the fuel supply for the plant. |
(2) | Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by Black Hills Power. This baseload plant is operated by PacifiCorp and our WRDC coal mine furnishes all of the fuel supply for the plant. |
(3) | Operations at the Osage plant were suspended October 1, 2010 due to the availability of more economical generation alternatives. |
(4) | Upon expiration of the contract with PacifiCorp in June 2012 (see below), the capacity of these units will be decreased to 80 MW. |
(5) | Colorado Electric entered into a 20-year PPA with Black Hills Colorado IPP for 200 MW of power from their gas-fired plants. This PPA, accounted for as a capital lease, was effective on January 1, 2012 upon completion of construction of the plants. |
(6) | In December 2010, Colorado Electric received a final order from the CPUC that approved the retirement of its W.N. Clark coal-fired generation facility by December 31, 2013. |
Fuel Source | 2011 | 2010 | 2009 | ||||||
Coal | $ | 15.89 | $ | 12.77 | $ | 13.99 | |||
Gas and Oil | $ | 150.00 | $ | 131.28 | $ | 85.52 | |||
Total Average Fuel Cost | $ | 16.77 | $ | 13.57 | $ | 15.22 | |||
Purchased Power - Coal, Gas and Oil | $ | 28.80 | $ | 29.57 | $ | 28.44 | |||
Purchased Power - Renewable Sources | $ | 46.71 | $ | 45.76 | $ | 43.66 |
Power Supply | 2011 | 2010 | 2009 | |||
Coal-fired | 38 | % | 42 | % | 39 | % |
Gas and Oil | — | — | 1 | |||
Total Generated | 38 | 42 | 40 | |||
Purchased | 62 | 58 | 60 | |||
Total | 100 | % | 100 | % | 100 | % |
• | Black Hills Power's PPA with PacifiCorp expiring in 2023, which provides for the purchase of 50 MW of coal-fired baseload power; |
• | Black Hills Power's reserve capacity integration agreement with PacifiCorp expiring in June 2012, which makes available 100 MW of reserve capacity in connection with the utilization of the Ben French CT units; |
• | Colorado Electric's PPA with Black Hills Colorado IPP expiring in 2031, which provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines; |
• | Colorado Electric's PPA with PSCo expiring at December 31, 2012, whereby Colorado Electric purchases 50 MW of economy energy; |
• | Colorado Electric's PPA with Cargill expiring at December 31, 2013, whereby Colorado Electric purchases 50 MW of economy energy; |
• | Cheyenne Light's PPA with Black Hills Wyoming expiring in August 2014, whereby Black Hills Wyoming provides 40 MW of energy and capacity from its Gillette CT; |
• | Cheyenne Light's PPA with Black Hills Wyoming expiring December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Cheyenne Light to purchase Black Hills Wyoming's ownership interest in the Wygen I facility between 2013 and 2019. The purchase price related to the option is $2.55 million per MW. This option price is reduced annually by an amount of annual depreciation assuming a facility life of 35 years; |
• | Cheyenne Light's 20-year PPA with Duke Energy expiring in 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 50% of the facility's output to Black Hills Power; |
• | Cheyenne Light and Black Hills Power's Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light's excess energy; and |
• | Cheyenne Light's 20-year PPA with Duke Energy expiring in 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 20 MW of energy from Silver Sage to Black Hills Power. |
• | MDU owns a 25% ownership interest in Wygen III's net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, Black Hills Power will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU; |
• | The City of Gillette owns a 23% ownership interest in Wygen III's net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, Black Hills Power will provide the City of Gillette with its first 23 MW from our other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves; |
• | Black Hills Power's agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchase over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: |
2012-2017 | 20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II |
2018-2019 | 15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
2020-2021 | 12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II |
2022-2023 | 10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II; |
• | Black Hills Power's PPA with MEAN, whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III through May 2015; and |
• | Cheyenne Light's agreement with Basin Electric, whereby Cheyenne Light will supply 40 MW of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 MW of capacity and energy from Basin Electric through March 31, 2013. |
Utility | State | Transmission (in Line Miles) | Distribution (in Line Miles) | ||
Black Hills Power | SD, WY | 618 | 2,999 | ||
Black Hills Power - Jointly Owned (1) | SD, WY | 47 | — | ||
Cheyenne Light | SD, WY | 25 | 1,235 | ||
Colorado Electric | CO | 243 | 3,329 |
(1) | Through Black Hills Power, we own 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. Black Hills Power's electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids. |
Revenue - Electric (in thousands) | 2011 | 2010 | 2009 | ||||||
Residential: | |||||||||
Black Hills Power | $ | 59,826 | $ | 53,549 | $ | 48,586 | |||
Cheyenne Light | 31,287 | 29,506 | 29,198 | ||||||
Colorado Electric | 84,646 | 76,596 | 66,548 | ||||||
Total Residential | 175,759 | 159,651 | 144,332 | ||||||
Commercial: | |||||||||
Black Hills Power | 72,889 | 65,997 | 59,897 | ||||||
Cheyenne Light | 55,331 | 52,765 | 51,280 | ||||||
Colorado Electric | 73,355 | 66,490 | 56,002 | ||||||
Total Commercial | 201,575 | 185,252 | 167,179 | ||||||
Industrial: | |||||||||
Black Hills Power | 25,723 | 22,621 | 20,014 | ||||||
Cheyenne Light | 11,629 | 10,542 | 11,121 | ||||||
Colorado Electric | 33,332 | 28,812 | 31,067 | ||||||
Total Industrial | 70,684 | 61,975 | 62,202 | ||||||
Municipal: | |||||||||
Black Hills Power | 3,172 | 3,029 | 2,735 | ||||||
Cheyenne Light | 1,765 | 1,293 | 932 | ||||||
Colorado Electric | 12,912 | 10,443 | 4,408 | ||||||
Total Municipal | 17,849 | 14,765 | 8,075 | ||||||
Subtotal Retail Revenue - Electric | 465,867 | 421,643 | 381,788 | ||||||
Contract Wholesale: | |||||||||
Black Hills Power | 18,105 | 22,996 | 25,358 | ||||||
Off-system Wholesale: | |||||||||
Black Hills Power | 34,889 | 36,354 | 32,212 | ||||||
Cheyenne Light | 9,371 | 9,750 | 8,565 | ||||||
Colorado Electric * | 13,018 | 10,859 | 14,008 | ||||||
Total Off-system Wholesale | 57,278 | 56,963 | 54,785 | ||||||
Other Revenue: | |||||||||
Black Hills Power | 31,027 | 25,217 | 18,277 | ||||||
Cheyenne Light | 2,449 | 3,230 | 718 | ||||||
Colorado Electric | 2,787 | 2,374 | 4,226 | ||||||
Total Other Revenue | 36,263 | 30,821 | 23,221 | ||||||
Total Revenue - Electric | $ | 577,513 | $ | 532,423 | $ | 485,152 |
* | Off-system sales revenue had been deferred by Colorado Electric from August 2010 until December 2011, when the CPUC approved a sharing mechanism as part of the rate case settlement allowing Colorado Electric a 25% share of off-system sales operating income. Revenue in 2011 represents off-system sales from August 2010 through December 2011. |
Quantities Generated and Purchased (MWh) | 2011 | 2010 | 2009 | |||
Generated - | ||||||
Coal-fired: | ||||||
Black Hills Power | 1,717,008 | 1,987,037 | 1,721,074 | |||
Cheyenne Light | 674,518 | 734,241 | 766,943 | |||
Colorado Electric | 268,317 | 257,896 | 252,603 | |||
Total Coal | 2,659,843 | 2,979,174 | 2,740,620 | |||
Gas and Oil-fired: | ||||||
Black Hills Power | 15,221 | 19,269 | 46,723 | |||
Cheyenne Light | — | — | — | |||
Colorado Electric | 2,342 | 930 | 2,705 | |||
Total Gas and Oil | 17,563 | 20,199 | 49,428 | |||
Total Generated: | ||||||
Black Hills Power | 1,732,229 | 2,006,306 | 1,767,797 | |||
Cheyenne Light | 674,518 | 734,241 | 766,943 | |||
Colorado Electric | 270,659 | 258,826 | 255,308 | |||
Total Generated | 2,677,406 | 2,999,373 | 2,790,048 | |||
Purchased - | ||||||
Black Hills Power | 1,720,640 | 1,440,579 | 1,686,455 | |||
Cheyenne Light | 745,983 | 696,756 | 651,201 | |||
Colorado Electric | 1,948,321 | 1,969,896 | 1,991,058 | |||
Total Purchased (a) | 4,414,944 | 4,107,231 | 4,328,714 | |||
Total Generated and Purchased | 7,092,350 | 7,106,604 | 7,118,762 |
Quantities (MWh) | 2011 | 2010 | 2009 | |||
Residential: | ||||||
Black Hills Power | 550,935 | 547,193 | 529,825 | |||
Cheyenne Light | 264,492 | 261,607 | 255,134 | |||
Colorado Electric | 629,752 | 628,553 | 589,526 | |||
Total Residential | 1,445,179 | 1,437,353 | 1,374,485 | |||
Commercial: | ||||||
Black Hills Power | 720,978 | 720,119 | 723,360 | |||
Cheyenne Light | 601,162 | 603,323 | 583,986 | |||
Colorado Electric | 720,060 | 726,005 | 666,563 | |||
Total Commercial | 2,042,200 | 2,049,447 | 1,973,909 | |||
Industrial: | ||||||
Black Hills Power | 408,337 | 382,562 | 353,041 | |||
Cheyenne Light | 172,840 | 161,082 | 174,792 | |||
Colorado Electric | 351,862 | 347,673 | 452,584 | |||
Total Industrial | 933,039 | 891,317 | 980,417 | |||
Municipal: | ||||||
Black Hills Power | 34,235 | 33,908 | 33,948 | |||
Cheyenne Light | 9,827 | 6,477 | 3,456 | |||
Colorado Electric | 126,320 | 113,689 | 37,244 | |||
Total Municipal | 170,382 | 154,074 | 74,648 | |||
Subtotal Retail Quantities Sold | 4,590,800 | 4,532,191 | 4,403,459 | |||
Contract Wholesale: | ||||||
Black Hills Power | 349,520 | 468,782 | 645,297 | |||
Off-system Wholesale: | ||||||
Black Hills Power | 1,226,548 | 1,163,058 | 1,009,574 | |||
Cheyenne Light | 278,528 | 311,524 | 309,122 | |||
Colorado Electric | 282,929 | 274,942 | 373,495 | |||
Total Off-system Wholesale | 1,788,005 | 1,749,524 | 1,692,191 | |||
Total Quantity Sold: | ||||||
Black Hills Power | 3,290,553 | 3,315,622 | 3,295,045 | |||
Cheyenne Light | 1,326,849 | 1,344,013 | 1,326,490 | |||
Colorado Electric | 2,110,923 | 2,090,862 | 2,119,412 | |||
Total Quantity Sold | 6,728,325 | 6,750,497 | 6,740,947 | |||
Losses and Company Use: | ||||||
Black Hills Power | 162,316 | 131,263 | 159,207 | |||
Cheyenne Light | 93,652 | 86,984 | 91,654 | |||
Colorado Electric | 108,057 | 137,860 | 126,954 | |||
Total Losses and Company Use | 364,025 | 356,107 | 377,815 | |||
Total Energy | 7,092,350 | 7,106,604 | 7,118,762 |
Customers at End of Year | 2011 | 2010 | 2009 | |||
Residential: | ||||||
Black Hills Power | 54,955 | 54,811 | 54,470 | |||
Cheyenne Light | 35,159 | 34,913 | 35,943 | |||
Colorado Electric | 81,811 | 81,902 | 81,622 | |||
Total Residential | 171,925 | 171,626 | 172,035 | |||
Commercial: | ||||||
Black Hills Power | 12,864 | 12,779 | 12,261 | |||
Cheyenne Light | 4,277 | 4,132 | 4,932 | |||
Colorado Electric | 11,206 | 11,185 | 11,101 | |||
Total Commercial | 28,347 | 28,096 | 28,294 | |||
Industrial: | ||||||
Black Hills Power | 45 | 40 | 38 | |||
Cheyenne Light | 2 | 2 | 2 | |||
Colorado Electric | 68 | 63 | 90 | |||
Total Industrial | 115 | 105 | 130 | |||
Other Electric Customers: | ||||||
Black Hills Power | 311 | 309 | 143 | |||
Cheyenne Light | 243 | 254 | 13 | |||
Colorado Electric | 506 | 510 | 499 | |||
Total Other Electric Customers | 1,060 | 1,073 | 655 | |||
Subtotal Retail Customers | 201,447 | 200,900 | 201,114 | |||
Contract Wholesale: | ||||||
Black Hills Power | 3 | 3 | 3 | |||
Total Customers: | ||||||
Black Hills Power | 68,178 | 67,942 | 66,915 | |||
Cheyenne Light | 39,681 | 39,301 | 40,890 | |||
Colorado Electric | 93,591 | 93,660 | 93,312 | |||
Total Customers at Year-End | 201,450 | 200,903 | 201,117 |
Degree Days | 2011 | 2010 | 2009 | ||||||
Actual | Variance from 30-Year Average | Actual | Variance from 30-Year Average | Actual | Variance from 30-Year Average | ||||
Heating Degree Days: | |||||||||
Black Hills Power | 7,579 | 5% | 7,272 | 1% | 7,753 | 8% | |||
Cheyenne Light | 7,321 | (1)% | 7,033 | (5)% | 7,411 | —% | |||
Colorado Electric | 5,749 | 3% | 5,518 | (1)% | 5,546 | (1)% | |||
Cooling Degree Days: | |||||||||
Black Hills Power | 700 | 17% | 532 | (11)% | 354 | (41)% | |||
Cheyenne Light | 431 | 58% | 345 | 26% | 203 | (26)% | |||
Colorado Electric | 1,259 | 37% | 1,074 | 16% | 804 | (13)% |
2011 | 2010 | 2009 | |||||||
Revenue - Gas (in thousands): | |||||||||
Residential | $ | 22,044 | $ | 22,562 | $ | 21,495 | |||
Commercial | 10,264 | 10,801 | 9,821 | ||||||
Industrial | 3,597 | 3,425 | 3,537 | ||||||
Other Sales Revenue | 913 | 803 | 760 | ||||||
Total Revenue - Gas | $ | 36,818 | $ | 37,591 | $ | 35,613 | |||
Gross Margin (in thousands): | |||||||||
Residential | $ | 10,426 | $ | 10,004 | $ | 10,219 | |||
Commercial | 3,345 | 3,376 | 3,266 | ||||||
Industrial | 504 | 427 | 509 | ||||||
Other Gross Margin | 545 | 720 | 760 | ||||||
Total Gross Margin | $ | 14,820 | $ | 14,527 | $ | 14,754 | |||
Volumes Sold (Dth): | |||||||||
Residential | 2,585,056 | 2,636,839 | 2,516,699 | ||||||
Commercial | 1,538,616 | 1,572,638 | 1,502,002 | ||||||
Industrial | 689,935 | 667,062 | 722,776 | ||||||
Total Volumes Sold | 4,813,607 | 4,876,539 | 4,741,477 | ||||||
Customers at Year-End | 34,807 | 34,461 | 33,942 |
Intrastate Gas Transmission Pipelines | Gas Distribution Mains | Gas Distribution Service Lines | ||||
Colorado | 124 | 2,987 | 886 | |||
Nebraska | 44 | 3,432 | 3,481 | |||
Iowa | 170 | 2,762 | 2,321 | |||
Kansas | 286 | 2,582 | 1,296 | |||
Total | 624 | 11,763 | 7,984 |
Revenue (in thousands) | 2011 | 2010 | 2009 | ||||||
Residential: | |||||||||
Colorado | $ | 58,102 | $ | 55,211 | $ | 62,732 | |||
Nebraska | 125,493 | 120,365 | 127,120 | ||||||
Iowa | 106,292 | 105,255 | 113,781 | ||||||
Kansas | 65,185 | 69,859 | 70,848 | ||||||
Total Residential | 355,072 | 350,690 | 374,481 | ||||||
Commercial: | |||||||||
Colorado | 12,172 | 11,880 | 13,357 | ||||||
Nebraska | 40,659 | 40,720 | 43,472 | ||||||
Iowa | 46,179 | 46,762 | 54,587 | ||||||
Kansas | 20,362 | 21,953 | 22,629 | ||||||
Total Commercial | 119,372 | 121,315 | 134,045 | ||||||
Industrial: | |||||||||
Colorado | 2,063 | 1,409 | 1,348 | ||||||
Nebraska | 860 | 3,126 | 3,425 | ||||||
Iowa | 2,521 | 2,243 | 2,191 | ||||||
Kansas | 19,571 | 14,312 | 11,057 | ||||||
Total Industrial | 25,015 | 21,090 | 18,021 | ||||||
Other Sales Revenue: | |||||||||
Colorado | 96 | 97 | 100 | ||||||
Nebraska | 1,971 | 1,960 | 2,077 | ||||||
Iowa | 550 | 836 | 1,073 | ||||||
Kansas | 3,031 | 3,451 | 3,213 | ||||||
Total Other Sales Revenue | 5,648 | 6,344 | 6,463 | ||||||
Total Distribution: | |||||||||
Colorado | 72,433 | 68,597 | 77,537 | ||||||
Nebraska | 168,983 | 166,171 | 176,094 | ||||||
Iowa | 155,542 | 155,096 | 171,632 | ||||||
Kansas | 108,149 | 109,575 | 107,747 | ||||||
Total Distribution | 505,107 | 499,439 | 533,010 | ||||||
Transportation: | |||||||||
Colorado | 846 | 784 | 732 | ||||||
Nebraska | 11,175 | 11,289 | 10,569 | ||||||
Iowa | 3,935 | 3,708 | 3,876 | ||||||
Kansas | 5,909 | 5,471 | 5,389 | ||||||
Total Transportation | 21,865 | 21,252 | 20,566 | ||||||
Total Regulated: | |||||||||
Colorado | 73,279 | 69,381 | 78,269 | ||||||
Nebraska | 180,158 | 177,460 | 186,663 | ||||||
Iowa | 159,477 | 158,804 | 175,508 | ||||||
Kansas | 114,058 | 115,046 | 113,136 | ||||||
Total Regulated Revenue | 526,972 | 520,691 | 553,576 | ||||||
Non-regulated Services | 27,612 | 30,016 | 26,736 | ||||||
Total Revenue | $ | 554,584 | $ | 550,707 | $ | 580,312 |
Gross Margin (in thousands) | 2011 | 2010 | 2009 | ||||||
Residential: | |||||||||
Colorado | $ | 17,711 | $ | 18,153 | $ | 17,443 | |||
Nebraska | 51,640 | 49,074 | 44,638 | ||||||
Iowa | 47,491 | 44,269 | 42,734 | ||||||
Kansas | 29,701 | 29,591 | 28,999 | ||||||
Total Residential | 146,543 | 141,087 | 133,814 | ||||||
Commercial: | |||||||||
Colorado | 2,960 | 3,215 | 3,176 | ||||||
Nebraska | 11,643 | 11,965 | 11,785 | ||||||
Iowa | 11,702 | 11,616 | 12,749 | ||||||
Kansas | 6,603 | 6,544 | 6,484 | ||||||
Total Commercial | 32,908 | 33,340 | 34,194 | ||||||
Industrial: | |||||||||
Colorado | 450 | 360 | 375 | ||||||
Nebraska | 217 | 379 | 431 | ||||||
Iowa | 288 | 235 | 244 | ||||||
Kansas | 2,373 | 1,878 | 1,766 | ||||||
Total Industrial | 3,328 | 2,852 | 2,816 | ||||||
Other Sales Margins: | |||||||||
Colorado | 96 | 97 | 101 | ||||||
Nebraska | 1,971 | 1,960 | 2,077 | ||||||
Iowa | 549 | 836 | 1,073 | ||||||
Kansas | 2,455 | 2,722 | 2,312 | ||||||
Total Other Sales Margins | 5,071 | 5,615 | 5,563 | ||||||
Total Distribution: | |||||||||
Colorado | 21,217 | 21,825 | 21,095 | ||||||
Nebraska | 65,471 | 63,378 | 58,931 | ||||||
Iowa | 60,030 | 56,956 | 56,800 | ||||||
Kansas | 41,132 | 40,735 | 39,561 | ||||||
Total Distribution | 187,850 | 182,894 | 176,387 | ||||||
Transportation: | |||||||||
Colorado | 846 | 784 | 732 | ||||||
Nebraska | 11,175 | 11,289 | 10,569 | ||||||
Iowa | 3,935 | 3,708 | 3,876 | ||||||
Kansas | 5,909 | 5,470 | 5,389 | ||||||
Total Transportation | 21,865 | 21,251 | 20,566 | ||||||
Total Regulated: | |||||||||
Colorado | 22,063 | 22,609 | 21,827 | ||||||
Nebraska | 76,646 | 74,667 | 69,500 | ||||||
Iowa | 63,965 | 60,664 | 60,676 | ||||||
Kansas | 47,041 | 46,205 | 44,950 | ||||||
Total Regulated Gross Margin | 209,715 | 204,145 | 196,953 | ||||||
Non-regulated Services | 12,908 | 12,845 | 11,643 | ||||||
Total Gross Margin | $ | 222,623 | $ | 216,990 | $ | 208,596 |
Volumes (in Dth) | 2011 | 2010 | 2009 | |||
Residential: | ||||||
Colorado | 6,437,860 | 6,284,559 | 6,355,275 | |||
Nebraska | 12,076,979 | 12,210,574 | 12,619,682 | |||
Iowa | 10,490,129 | 10,556,045 | 10,976,268 | |||
Kansas | 6,853,163 | 6,926,928 | 6,878,243 | |||
Total Residential | 35,858,131 | 35,978,106 | 36,829,468 | |||
Commercial: | ||||||
Colorado | 1,472,747 | 1,473,924 | 1,444,360 | |||
Nebraska | 4,833,604 | 5,009,105 | 5,189,630 | |||
Iowa | 6,192,167 | 6,061,954 | 6,597,035 | |||
Kansas | 2,676,439 | 2,673,805 | 2,696,870 | |||
Total Commercial | 15,174,957 | 15,218,788 | 15,927,895 | |||
Industrial: | ||||||
Colorado | 344,576 | 259,985 | 263,134 | |||
Nebraska | 120,779 | 544,457 | 581,892 | |||
Iowa | 409,723 | 354,435 | 333,324 | |||
Kansas | 3,743,735 | 2,718,767 | 2,524,126 | |||
Total Industrial | 4,618,813 | 3,877,644 | 3,702,476 | |||
Other Volumes: | ||||||
Colorado | — | — | — | |||
Nebraska | — | 1,341 | 1,400 | |||
Iowa | — | 69,306 | 68,290 | |||
Kansas | 112,253 | 120,445 | 141,909 | |||
Total Other Volumes | 112,253 | 191,092 | 211,599 | |||
Total Distribution: | ||||||
Colorado | 8,255,183 | 8,018,468 | 8,062,769 | |||
Nebraska | 17,031,362 | 17,765,477 | 18,392,604 | |||
Iowa | 17,092,019 | 17,041,740 | 17,974,917 | |||
Kansas | 13,385,590 | 12,439,945 | 12,241,148 | |||
Total Distribution | 55,764,154 | 55,265,630 | 56,671,438 | |||
Transportation: | ||||||
Colorado | 869,570 | 808,859 | 807,999 | |||
Nebraska | 24,972,560 | 27,327,173 | 25,311,501 | |||
Iowa | 18,358,692 | 17,422,525 | 14,915,602 | |||
Kansas | 15,015,310 | 14,320,893 | 14,069,182 | |||
Total Transportation | 59,216,132 | 59,879,450 | 55,104,284 | |||
Total Volumes: | ||||||
Colorado | 9,124,753 | 8,827,327 | 8,870,768 | |||
Nebraska | 42,003,922 | 45,092,650 | 43,704,105 | |||
Iowa | 35,450,711 | 34,464,265 | 32,890,519 | |||
Kansas | 28,400,900 | 26,760,838 | 26,310,330 | |||
Total Volumes | 114,980,286 | 115,145,080 | 111,775,722 |
2011 | 2010 | 2009 | |||||||
Actual | Variance From 30-Year Average | Actual | Variance From 30-Year Average | Actual | Variance From 30-Year Average | ||||
Heating Degree Days (a): | |||||||||
Colorado | 5,991 | (7)% | 5,803 | (9)% | 6,299 | 2% | |||
Nebraska | 6,190 | (4)% | 6,222 | (5)% | 6,238 | 5% | |||
Iowa | 7,013 | (1)% | 6,934 | (1)% | 7,279 | 6% | |||
Kansas (b) | 4,954 | (1)% | 4,918 | —% | 4,989 | —% | |||
Combined | 6,143 | (3)% | 6,101 | (3)% | 6,285 | (11)% |
(a) | The combined heating degree days are calculated based on a weighted average of total customers by state. |
(b) | In Kansas where we have a weather normalization mechanism, normal degree days are used instead of actual degree days in computing the total number of heating degree days. |
Customers | 2011 | 2010 | 2009 | |||
Residential: | ||||||
Colorado | 67,496 | 66,766 | 65,586 | |||
Nebraska | 176,386 | 176,244 | 179,873 | |||
Iowa | 135,161 | 134,782 | 133,712 | |||
Kansas | 98,043 | 97,844 | 97,446 | |||
Total Residential | 477,086 | 475,636 | 476,617 | |||
Commercial: | ||||||
Colorado | 3,678 | 3,620 | 3,590 | |||
Nebraska | 15,664 | 15,221 | 15,218 | |||
Iowa | 15,398 | 15,300 | 15,403 | |||
Kansas | 9,453 | 9,469 | 9,510 | |||
Total Commercial | 44,193 | 43,610 | 43,721 | |||
Industrial: | ||||||
Colorado | 209 | 208 | 207 | |||
Nebraska | 141 | 149 | 149 | |||
Iowa | 94 | 93 | 90 | |||
Kansas | 1,365 | 1,394 | 1,351 | |||
Total Industrial | 1,809 | 1,844 | 1,797 | |||
Transportation: | ||||||
Colorado | 30 | 22 | 22 | |||
Nebraska | 4,128 | 4,270 | 4,579 | |||
Iowa | 393 | 392 | 389 | |||
Kansas | 1,142 | 1,054 | 1,077 | |||
Total Transportation | 5,693 | 5,738 | 6,067 | |||
Other: | ||||||
Colorado | — | — | — | |||
Nebraska | — | 2 | 2 | |||
Iowa | — | 68 | 71 | |||
Kansas | 7 | 8 | 8 | |||
Total Other | 7 | 78 | 81 | |||
Total Customers: | ||||||
Colorado | 71,413 | 70,616 | 69,405 | |||
Nebraska | 196,319 | 195,886 | 199,821 | |||
Iowa | 151,046 | 150,635 | 149,665 | |||
Kansas | 110,010 | 109,769 | 109,392 | |||
Total Customers at Year-End | 528,788 | 526,906 | 528,283 |
• | In South Dakota, Wyoming, Colorado and Montana, we have cost adjustment mechanisms for our Electric Utilities that serve a purpose similar to the cost adjustment mechanisms in our Gas Utilities. At Cheyenne Light, our pass-through mechanism relating to transmission, fuel and purchased power costs is subject to a $1.0 million threshold: we collect or refund 95% of the increase or decrease that exceeds the $1.0 million threshold, and we absorb the increase or retain the savings for costs below the threshold as well as the 5% not collected or refunded above the threshold. |
• | Until April 1, 2010, South Dakota had three adjustment mechanisms: transmission, steam plant fuel (coal) and conditional ECA. The transmission and steam plant fuel adjustment clauses required an annual adjustment to rates for actual costs. Therefore, any savings or increased costs were passed on to the South Dakota customers. The conditional ECA related to purchased power and natural gas used to generate electricity. These costs were subject to calendar year $2.0 million and $1.0 million thresholds where Black Hills Power absorbed the first $2.0 million of increased costs or retained the first $1.0 million in savings. Beyond these thresholds, costs or savings were passed on to South Dakota customers through annual calendar-year filings. |
• | In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect June 1, 2011 and recovers all the costs associated with plant additions. |
• | In Colorado, we have an ECA for increases or decreases in purchased power and fuel costs and a TCA for transmission cost adjustments. The ECA clause provides for the direct recovery of increased purchased power and fuel costs or the issuance of credits for decreases in purchased power and fuel costs. The TCA is a rider to the customer's bill which allows the utility to earn an authorized return on new transmission investment and recovery of operations and maintenance costs related to transmission. |
• | Effective January 1, 2012, the CPUC approved adjustments to the ECA. These adjustments allow for the recovery of transmission expenses paid to other providers, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs, where the customer receives 75% through 2013. This sharing percentage increases to 90% to the customer in 2014. |
• | In Colorado, beginning in November 2010, the CPUC approved the implementation of a Purchased Capacity Cost Adjustment, the purpose of which is to recover the increase in capacity cost related to Colorado Electric's purchase power agreement with PSCo. This Purchase Capacity Cost Adjustment expired on January 1, 2012 in conjunction with expiration of the PPA with PSCo and the commencement of Colorado Electric's PPA with Colorado IPP. |
• | South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015. Absent a specific renewable energy mandate in South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers. |
• | Montana. Montana established a renewable portfolio standard that requires Black Hills Power to obtain a percentage of its retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 5% for compliance years 2008-2009; (ii) 10% for compliance years 2010-2014; and (iii) 15% for compliance year 2015 and thereafter. Utilities can meet this standard by entering into long-term purchase contracts for electricity bundled with renewable-energy credits, by purchasing the renewable-energy credits separately, or by a combination of both. The law includes cost caps that limit the additional cost utilities must pay for renewable energy and allows cost recovery from ratepayers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards. |
• | Colorado. Colorado has adopted a renewable energy standard that requires our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 12% of retail sales from 2011 to 2014; (ii) 20% of retail sales from 2015 to 2019; and (iii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The law limits the net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) to 2% and encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We are currently in compliance with these standards, and our current strategy is to incorporate renewable energy as required to comply with the standards. |
• | Wyoming. Wyoming is also exploring the implementation of renewable energy portfolio standards but has not currently adopted standards. |
Approved Capital Structure | |||||||||||||||
Type of Service | Date Requested | Date Effective | Amount Requested | Amount Approved | Return on Equity | Equity | Debt | ||||||||
Nebraska Gas (1) | Gas | 12/2009 | 9/2010 | $ | 12.1 | $ | 8.3 | 10.1 | % | 52.0 | % | 48.0 | % | ||
Iowa Gas | Gas | 6/2008 | 7/2009 | $ | 13.6 | $ | 10.8 | 10.1 | % | 51.4 | % | 48.6 | % | ||
Iowa Gas (2) | Gas | 6/2010 | 2/2011 | $ | 4.7 | $ | 3.4 | Global Settlement | Global Settlement | Global Settlement | |||||
Colorado Gas | Gas | 6/2008 | 4/2009 | $ | 2.7 | $ | 1.4 | 10.3 | % | 50.5 | % | 49.5 | % | ||
Kansas Gas | Gas | 5/2009 | 10/2009 | $ | 0.5 | $ | 0.5 | 10.2 | % | 50.7 | % | 49.3 | % | ||
Black Hills Power (3) | Electric | 9/2009 | 4/2010 | $ | 32.0 | $ | 15.2 | Global Settlement | Global Settlement | Global Settlement | |||||
Black Hills Power (4) | Electric | 10/2009 | 6/2010 | $ | 3.8 | $ | 3.1 | 10.5 | % | 52.0 | % | 48.0 | % | ||
Black Hills Power (5) | Electric | 1/2011 | 6/2011 | Not Applicable | $ | 3.1 | Not Applicable | Not Applicable | Not Applicable | ||||||
Colorado Electric (6) | Electric | 1/2010 | 8/2010 | $ | 22.9 | $ | 17.9 | 10.5 | % | 52.0 | % | 48.0 | % | ||
Colorado Electric (7) | Electric | 4/2011 | 1/2012 | $ | 40.2 | $ | 28.0 | 9.8%-10.2% | 49.1 | % | 50.9 | % | |||
Cheyenne Light (8) | Electric/Gas | 12/2011 | pending | $ | 8.5 | pending | pending | pending | pending |
(1) | In December 2009, Nebraska Gas filed a rate case with the NPSC and interim rates went into effect on March 1, 2010. In August 2010, NPSC issued a decision approving an annual revenue increase of approximately $8.3 million, based on a return on equity of 10.1% with a capital structure of 52% equity effective September 1, 2010. A refund to customers for the difference between interim rates and approved rates was completed in the first quarter of 2011. The Nebraska Public Advocate has filed an appeal with the District Court which has been denied. Subsequently, the Nebraska Public Advocate has filed a notice of appeal in the Court of Appeals. This appeal is still outstanding. |
(2) | In June 2010, Iowa Gas filed a request with the IUB for a $4.7 million revenue increase to recover the cost of capital investments made in our gas distribution system and other expense increases incurred since December 2008. Interim rates, subject to refund, equal to a $2.6 million increase in revenues went into effect on June 18, 2010. In August 2010, we reached a settlement with the OCA for a revenue increase of $3.4 million. This settlement agreement was modified and re-filed on January 11, 2011. The modified settlement excludes the integrity investment tracker and the three-year rate moratorium included in the original settlement agreement filed on September 1, 2010, which was not approved by the IUB. Approval from the IUB was received on February 10, 2011. |
(3) | In September 2009, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the previous four years. In March 2010, the SDPUC approved a $24.1 million increase in interim rates, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million and a base rate increase of $22.0 million with an effective date of April 1, 2010. The approved capital structure and return on equity are confidential. A refund was provided to customers in the third quarter of 2010. |
(4) | In October 2009, Black Hills Power filed a rate case with the WPSC requesting a $3.8 million electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. On May 4, 2010, Black Hills Power filed a settlement stipulation agreement with the WPSC for a $3.1 million increase in annual revenues. On May 13, 2010, WPSC approved these new rates based on a return on equity of 10.5% with a capital structure of 52% equity and 48% debt. New rates went into effect on June 1, 2010. |
(5) | In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase of $3.1 million. |
(6) | In January 2010, Colorado Electric filed a rate case with the CPUC requesting an electric revenue increase primarily related to the recovery of rising costs from electricity supply contracts, as well as recovery for investment in equipment and electricity distribution facilities necessary to maintain and strengthen the reliability of the electric delivery system in Colorado. On August 5, 2010, the CPUC approved a settlement agreement for $17.9 million in annual revenues with a return on equity of 10.5% and a capital structure of 52% equity and 48% debt. New rates were effective August 6, 2010. |
(7) | In April 2011, Colorado Electric filed a request with the CPUC for an annual revenue increase of $40.2 million, or 18.8%, to recover costs and a return on capital associated with the 180 MW generating facility that commenced commercial operation on January 1, 2012, associated infrastructure assets and other utility expenses, including the PPA with Colorado IPP. On December 22, 2011, the CPUC issued an order approving an annual base rate increase of $10.5 million with a rate of return ranging from 9.8% to 10.2% with a capital structure of 49.1% equity and 50.9% debt. New rates were effective January 1, 2012. In addition, approximately $17.5 million of other costs including fuel, purchased power and new transmission will be recovered through normal cost adjustment mechanisms. |
(8) | On December 1, 2011, Cheyenne Light filed requests for electric and natural gas revenue increases with the WPSC to recover investment in infrastructure and other costs. Cheyenne Light is seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue. |
Environmental Expenditure Estimates | Total (in millions) | ||
2012 | $ | 12 | |
2013 | 39 | ||
2014 | 13 | ||
Total | $ | 64 |
• | Oil and Gas |
• | Power Generation |
• | Coal Mining |
Proved Reserves | December 31, 2011 | |||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||
Developed - | ||||||||||||
Natural Gas (MMcf) | 71,867 | 15,598 | 36,463 | 1,954 | 8,926 | 8,926 | ||||||
Oil (Mbbl) | 4,830 | — | 12 | 1,247 | 3,549 | 22 | ||||||
Total Developed (MMcfe) | 100,847 | 15,598 | 36,535 | 9,436 | 30,220 | 9,058 | ||||||
Undeveloped - | ||||||||||||
Natural Gas (MMcf) | 24,031 | 12,765 | 8,132 | 2,102 | — | 1,032 | ||||||
Oil (Mbbl) | 1,394 | — | — | 1,394 | — | — | ||||||
Total Undeveloped (MMcfe) | 32,395 | 12,765 | 8,132 | 10,466 | — | 1,032 | ||||||
Total MMcfe | 133,242 | 28,363 | 44,667 | 19,902 | 30,220 | 10,090 |
Proved Reserves | December 31, 2010 | |||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||
Developed - | ||||||||||||
Natural Gas (MMcf) | 67,656 | 11,475 | 36,281 | 679 | 10,180 | 9,041 | ||||||
Oil (Mbbl) | 4,434 | — | 11 | 508 | 3,891 | 24 | ||||||
Total Developed (MMcfe) | 94,260 | 11,475 | 36,347 | 3,727 | 33,526 | 9,185 | ||||||
Undeveloped - | ||||||||||||
Natural Gas (MMcf) | 27,800 | 21,777 | 620 | 1,820 | — | 3,583 | ||||||
Oil (Mbbl) | 1,506 | — | — | 1,506 | — | — | ||||||
Total Undeveloped (MMcfe) | 36,836 | 21,777 | 620 | 10,856 | — | 3,583 | ||||||
Total MMcfe | 131,096 | 33,252 | 36,967 | 14,583 | 33,526 | 12,768 |
Proved Reserves | December 31, 2009 | |||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||
Developed - | ||||||||||||
Natural Gas (MMcf) | 74,911 | 14,247 | 39,276 | 237 | 10,711 | 10,440 | ||||||
Oil (Mbbl) | 4,274 | — | 7 | 162 | 4,068 | 37 | ||||||
Total Developed (MMcfe) | 100,555 | 14,247 | 39,318 | 1,209 | 35,119 | 10,662 | ||||||
Undeveloped - | ||||||||||||
Natural Gas (MMcf) | 12,749 | 5,054 | 3,030 | 768 | 460 | 3,437 | ||||||
Oil (Mbbl) | 1,000 | — | — | 516 | 484 | — | ||||||
Total Undeveloped (MMcfe) | 18,749 | 5,054 | 3,030 | 3,864 | 3,364 | 3,437 | ||||||
Total MMcfe | 119,304 | 19,301 | 42,348 | 5,073 | 38,483 | 14,099 |
Crude Oil | December 31, 2011 | |||||||||||
(in Mbbl) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 5,940 | — | 11 | 2,014 | 3,891 | 24 | ||||||
Production | (452 | ) | — | (2 | ) | (182 | ) | (264 | ) | (4 | ) | |
Additions - acquisitions (sales) | (84 | ) | — | — | — | (84 | ) | — | ||||
Additions - extensions and discoveries | 927 | — | — | 927 | — | — | ||||||
Revisions to previous estimates | (108 | ) | — | 3 | (118 | ) | 6 | 1 | ||||
Balance at end of year | 6,223 | — | 12 | 2,641 | 3,549 | 21 |
Natural Gas | December 31, 2011 | |||||||||||
(in MMcf) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 95,456 | 33,252 | 36,901 | 2,499 | 10,180 | 12,624 | ||||||
Production | (8,526 | ) | (1,077 | ) | (5,063 | ) | (173 | ) | (516 | ) | (1,697 | ) |
Additions - acquisitions (sales) | — | — | — | — | — | — | ||||||
Additions - extensions and discoveries | 29,664 | 16,797 | 11,109 | 1,460 | — | 298 | ||||||
Revisions to previous estimates (a) | (20,690 | ) | (20,609 | ) | 1,648 | 270 | (738 | ) | (1,261 | ) | ||
Balance at end of year | 95,904 | 28,363 | 44,595 | 4,056 | 8,926 | 9,964 |
(a) | Included in the total revisions are (23.6) Bcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2.3 Bcfe in various basins. Revisions due to cost and commodity pricing were less than 1% of total reserve quantities. |
December 31, 2011 | ||||||||||||
Total MMcfe (a) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 131,096 | 33,252 | 36,967 | 14,583 | 33,526 | 12,768 | ||||||
Production | (11,238 | ) | (1,077 | ) | (5,075 | ) | (1,265 | ) | (2,100 | ) | (1,721 | ) |
Additions - acquisitions (sales) | (504 | ) | — | — | — | (504 | ) | — | ||||
Additions - extensions and discoveries | 35,226 | 16,797 | 11,109 | 7,022 | — | 298 | ||||||
Revisions to previous estimates (b) | (21,338 | ) | (20,609 | ) | 1,666 | (438 | ) | (702 | ) | (1,255 | ) | |
Balance at end of year | 133,242 | 28,363 | 44,667 | 19,902 | 30,220 | 10,090 |
(a) | Production for reserve calculations does not include volumes for NGLs. |
Crude Oil | December 31, 2010 | |||||||||||
(in Mbbl) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 5,274 | — | 7 | 678 | 4,552 | 37 | ||||||
Production | (376 | ) | — | (2 | ) | (84 | ) | (280 | ) | (10 | ) | |
Additions - acquisitions | (13 | ) | — | — | — | — | (13 | ) | ||||
Additions - extensions and discoveries | 1,145 | — | — | 1,099 | 46 | — | ||||||
Revisions to previous estimates (a) | (90 | ) | — | 6 | 321 | (427 | ) | 10 | ||||
Balance at end of year | 5,940 | — | 11 | 2,014 | 3,891 | 24 |
Natural Gas | December 31, 2010 | |||||||||||
(in MMcf) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 87,660 | 19,301 | 42,306 | 1,005 | 11,171 | 13,877 | ||||||
Production | (8,484 | ) | (1,077 | ) | (5,056 | ) | — | (314 | ) | (2,037 | ) | |
Additions - acquisitions | (377 | ) | — | — | — | — | (377 | ) | ||||
Additions - extensions and discoveries | 1,710 | — | 372 | 1,334 | — | 4 | ||||||
Revisions to previous estimates (a) | 14,947 | 15,028 | (721 | ) | 160 | (677 | ) | 1,157 | ||||
Balance at end of year | 95,456 | 33,252 | 36,901 | 2,499 | 10,180 | 12,624 |
December 31, 2010 | ||||||||||||
Total MMcfe (b) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 119,304 | 19,301 | 42,348 | 5,073 | 38,483 | 14,099 | ||||||
Production | (10,740 | ) | (1,077 | ) | (5,068 | ) | (504 | ) | (1,994 | ) | (2,097 | ) |
Additions - acquisitions | (455 | ) | — | — | — | — | (455 | ) | ||||
Additions - extensions and discoveries | 8,580 | — | 372 | 7,928 | 276 | 4 | ||||||
Revisions to previous estimates (a) | 14,407 | 15,028 | (685 | ) | 2,086 | (3,239 | ) | 1,217 | ||||
Balance at end of year | 131,096 | 33,252 | 36,967 | 14,583 | 33,526 | 12,768 |
(a) | Revisions to previous estimates for 2010 primarily due to price changes. |
(b) | Production for reserve calculations does not include volumes for NGLs. |
Crude Oil | December 31, 2009 | |||||||||||
(in Mbbl) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 5,185 | — | 13 | 523 | 4,607 | 42 | ||||||
Production | (366 | ) | — | (3 | ) | (32 | ) | (321 | ) | (10 | ) | |
Additions - acquisitions | — | — | — | — | — | — | ||||||
Additions - extensions and discoveries | 152 | — | — | 152 | — | — | ||||||
Revisions to previous estimates (a) | 303 | — | (3 | ) | 35 | 266 | 5 | |||||
Balance at end of year | 5,274 | — | 7 | 678 | 4,552 | 37 |
Natural Gas | December 31, 2009 | |||||||||||
(in MMcf) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 154,432 | 54,922 | 64,258 | 811 | 10,724 | 23,717 | ||||||
Production | (9,710 | ) | (1,263 | ) | (5,571 | ) | — | (297 | ) | (2,579 | ) | |
Additions - acquisitions | — | — | — | — | — | — | ||||||
Additions - extensions and discoveries | 2,560 | — | 2,135 | 222 | — | 203 | ||||||
Revisions to previous estimates (a) | (59,622 | ) | (34,358 | ) | (18,516 | ) | (28 | ) | 744 | (7,464 | ) | |
Balance at end of year | 87,660 | 19,301 | 42,306 | 1,005 | 11,171 | 13,877 |
December 31, 2009 | ||||||||||||
Total MMcfe (b) | Total | Piceance | San Juan | Williston | Powder River | Other | ||||||
Balance at beginning of year | 185,542 | 54,922 | 64,336 | 3,949 | 38,366 | 23,969 | ||||||
Production | (11,906 | ) | (1,263 | ) | (5,589 | ) | (192 | ) | (2,223 | ) | (2,639 | ) |
Additions - acquisitions | — | — | — | — | — | — | ||||||
Additions - extensions and discoveries | 3,472 | — | 2,135 | 1,134 | — | 203 | ||||||
Revisions to previous estimates (a) | (57,804 | ) | (34,358 | ) | (18,534 | ) | 182 | 2,340 | (7,434 | ) | ||
Balance at end of year | 119,304 | 19,301 | 42,348 | 5,073 | 38,483 | 14,099 |
(a) | Revisions to previous estimates for 2009 primarily due to price changes. |
(b) | Production for reserve calculations does not include volumes for NGLs. |
Year ended December 31, 2011 | ||||||
Location | Oil (in Bbl) | Natural Gas (Mcfe) | Total (Mcfe) | |||
San Juan | 1,746 | 5,062,662 | 5,073,138 | |||
Piceance | — | 1,111,421 | 1,111,421 | |||
Powder River | 264,358 | 942,573 | 2,528,721 | |||
Williston | 181,580 | 172,949 | 1,262,429 | |||
All other properties | 4,139 | 1,761,788 | 1,786,622 | |||
Total Volume | 451,823 | 9,051,393 | 11,762,331 |
Year ended December 31, 2010 | ||||||
Location | Oil (in Bbl) | Natural Gas (Mcfe) | Total (Mcfe) | |||
San Juan | 2,403 | 5,055,635 | 5,070,053 | |||
Piceance | — | 1,111,724 | 1,111,724 | |||
Powder River | 280,351 | 842,385 | 2,524,491 | |||
Williston | 84,472 | — | 506,832 | |||
All other properties | 8,419 | 2,036,755 | 2,087,269 | |||
Total Volume | 375,645 | 9,046,499 | 11,300,369 |
Year ended December 31, 2009 | ||||||
Location | Oil (in Bbl) | Natural Gas (Mcfe) | Total (Mcfe) | |||
San Juan | 2,547 | 5,570,741 | 5,586,023 | |||
Piceance | — | 1,298,924 | 1,298,924 | |||
Powder River | 320,752 | 818,709 | 2,743,221 | |||
Williston | 32,311 | — | 193,866 | |||
All other properties | 10,342 | 2,578,498 | 2,640,550 | |||
Total Volume | 365,952 | 10,266,872 | 12,462,584 |
December 31, 2011 | December 31, 2010 | |||||
Proved developed reserves as a percentage of total proved reserves on an MMcfe basis | 76 | % | 72 | % | ||
Proved undeveloped reserves as a percentage of total proved reserves on an MMcfe basis | 24 | % | 28 | % | ||
Present value of estimated future net revenues, before tax, discounted at 10% (in thousands) | $ | 255,087 | $ | 196,554 |
December 31, 2011 | ||||||||||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||||||||
Gas per Mcf | $ | 3.59 | $ | 3.73 | $ | 3.37 | $ | 3.07 | $ | 4.36 | $ | 3.83 | ||||||
Oil per Bbl | $ | 88.49 | $ | — | $ | 80.80 | $ | 85.05 | $ | 91.09 | $ | 84.61 |
December 31, 2010 | ||||||||||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||||||||
Gas per Mcf | $ | 3.45 | $ | 3.21 | $ | 3.50 | $ | 3.57 | $ | 3.62 | $ | 3.79 | ||||||
Oil per Bbl | $ | 70.82 | $ | — | $ | 66.36 | $ | 69.32 | $ | 71.62 | $ | 68.52 |
December 31, 2009 | ||||||||||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||||||||
Gas per Mcf | $ | 2.52 | $ | 1.57 | $ | 2.58 | $ | 4.84 | $ | 2.72 | $ | 3.82 | ||||||
Oil per Bbl | $ | 53.59 | $ | — | $ | 52.31 | $ | 52.64 | $ | 53.77 | $ | 49.16 |
Year ended December 31, | 2011 | 2010 | 2009 | |||||||||
Net Development Wells | Productive | Dry | Productive | Dry | Productive | Dry | ||||||
Piceance | — | — | — | — | — | — | ||||||
San Juan | 1.00 | — | 5.60 | — | 3.00 | — | ||||||
Williston | 1.73 | — | 0.67 | — | 0.04 | — | ||||||
Powder River | — | — | 2.66 | — | — | — | ||||||
Other | 3.59 | — | — | — | 4.37 | 1.04 | ||||||
Total net development wells | 6.32 | — | 8.93 | — | 7.41 | 1.04 |
Year ended December 31, | 2011 | 2010 | 2009 | |||||||||
Net Exploratory Wells | Productive | Dry | Productive | Dry | Productive | Dry | ||||||
Piceance | 0.99 | — | — | — | 0.91 | — | ||||||
San Juan | 0.80 | — | — | — | — | — | ||||||
Williston | — | — | — | — | 0.03 | — | ||||||
Powder River | — | — | — | — | — | 0.50 | ||||||
Other | 0.25 | 1.70 | — | — | 0.50 | 0.37 | ||||||
Total net exploratory wells | 2.04 | 1.70 | — | — | 1.44 | 0.87 |
December 31, 2011 | ||||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||
Gross Productive: | ||||||||||||
Crude Oil | 462 | — | 2 | 56 | 398 | 6 | ||||||
Natural Gas | 757 | 66 | 218 | — | 1 | 472 | ||||||
Total | 1,219 | 66 | 220 | 56 | 399 | 478 | ||||||
Net Productive: | ||||||||||||
Crude Oil | 299.10 | — | 1.91 | 3.97 | 292.45 | 0.77 | ||||||
Natural Gas | 322.57 | 53.63 | 201.40 | — | 0.06 | 67.48 | ||||||
Total | 621.67 | 53.63 | 203.31 | 3.97 | 292.51 | 68.25 |
December 31, 2010 | ||||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||
Gross Productive: | ||||||||||||
Crude Oil | 463 | 1 | 2 | 38 | 418 | 4 | ||||||
Natural Gas | 828 | 88 | 225 | — | 7 | 508 | ||||||
Total | 1,291 | 89 | 227 | 38 | 425 | 512 | ||||||
Net Productive: | ||||||||||||
Crude Oil | 312.09 | — | 1.91 | 2.46 | 307.23 | 0.49 | ||||||
Natural Gas | 355.90 | 66.23 | 214.82 | — | 0.73 | 74.12 | ||||||
Total | 667.99 | 66.23 | 216.73 | 2.46 | 307.96 | 74.61 |
December 31, 2009 | ||||||||||||
Total | Piceance | San Juan | Williston | Powder River | Other | |||||||
Gross Productive: | ||||||||||||
Crude Oil | 454 | 1 | 2 | 29 | 416 | 6 | ||||||
Natural Gas | 860 | 86 | 220 | — | 20 | 534 | ||||||
Total | 1,314 | 87 | 222 | 29 | 436 | 540 | ||||||
Net Productive: | ||||||||||||
Crude Oil | 314.47 | — | 1.91 | 2.51 | 309.40 | 0.65 | ||||||
Natural Gas | 355.20 | 65.93 | 210.21 | — | 2.50 | 76.56 | ||||||
Total | 669.67 | 65.93 | 212.12 | 2.51 | 311.90 | 77.21 |
Undeveloped | Developed | Total | ||||||||||
Gross | Net * | Gross | Net | Gross | Net | |||||||
Piceance | 39,569 | 30,816 | 37,326 | 33,194 | 76,895 | 64,010 | ||||||
San Juan | 40,997 | 39,569 | 26,142 | 22,725 | 67,139 | 62,294 | ||||||
Williston | 18,796 | 1,910 | 40,301 | 5,600 | 59,097 | 7,510 | ||||||
Powder River | 79,439 | 41,651 | 32,804 | 17,091 | 112,243 | 58,742 | ||||||
Bear Paw Uplift (MT) | 351,119 | 63,428 | 106,748 | 19,877 | 457,867 | 83,305 | ||||||
Other | 66,002 | 46,141 | 28,584 | 5,653 | 94,586 | 51,794 | ||||||
Total | 595,922 | 223,515 | 271,905 | 104,140 | 867,827 | 327,655 |
* | Approximately 4.7% (52,061 gross and 10,492 net acres) and 15.8% (125,063 gross and 35,120 net acres) and 6.5% (59,832 gross and 14,362 net acres) of our net undeveloped acreage could expire in 2012, 2013 and 2014, respectively, if production is not established on the leases or further action is not taken to extend the associated lease terms. Decisions on extending leases are based on expected exploration or development potential under the prevailing economic conditions. |
Power Plants(1) | Fuel Type | Location | Ownership Interest | Owned Capacity (MW) | Start Date | |
Gillette CT | Gas | Gillette, Wyoming | 100.0% | 40.0 | 2001 | |
Wygen I | Coal | Gillette, Wyoming | 76.5% | 68.9 | 2003 | |
108.9 | ||||||
Power Plant | Fuel Type | Location | Ownership Interest | Owned and Leased (MW) | Start Date | |
Pueblo Airport Generation (2) | Gas | Pueblo, CO | 100.0% | 200.0 | 2012 | |
Total Owned Capacity | 308.9 |
(1) | On January 18, 2011, we sold our ownership interest in the partnerships that owned the Glenns Ferry and Rupert Cogeneration facilities. |
(2) | The plant commenced commercial operation on January 1, 2012. Black Hills Colorado IPP has the obligation to operate this facility under the 20-year PPA which is accounted for as a capital lease. |
• | Our regulated electric utilities, Black Hills Power and Cheyenne Light; |
• | The 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by Black Hills Power under which PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. This contract expires at the end of December 2022; |
• | The 110 MW Wygen III power plant owned 52% by Black Hills Power, 25% by MDU and 23% by the City of Gillette; |
• | The 90 MW non-regulated mine-mouth power plant, Wygen I, owned 76.5% by Black Hills Wyoming and 23.5% by MEAN; and |
• | Certain regional industrial customers served by truck. |
• | Approximately 8,800 square feet for an operations and customer call center in Rapid City, South Dakota; |
• | Approximately 37,600 square feet for a customer call center in Lincoln, Nebraska; |
• | Approximately 47,430 square feet of office space in Denver, Colorado; and |
• | Other offices and warehouse facilities located within our service areas. |
Number of Employees | ||
Corporate | 391 | |
Utilities | 1,451 | |
Non-regulated Energy * | 188 | |
Total | 2,030 |
* | Excludes 44 Energy Marketing employees of our discontinued operations subsidiary, Enserco, due to the proposed sale of Enserco. |
Utility | Number of Employees | Union Affiliation | Expiration Date of Collective Bargaining Agreement | |
Black Hills Power | 161 | IBEW Local 1250 | March 31, 2012 | |
Cheyenne Light | 48 | IBEW Local 111 | June 30, 2016 | |
Colorado Electric | 138 | IBEW Local 667 | April 15, 2015 | |
Iowa Gas | 137 | IBEW Local 204 | August 1, 2015 | |
Kansas Gas | 21 | Communications Workers of America, AFL-CIO Local 6407 | December 31, 2014 | |
Nebraska Gas | 159 | IBEW Local 244 | March 13, 2014 | |
Total | 664 |
ITEM 1A. | RISK FACTORS |
• | Commodity prices can often be volatile. A decline in oil and natural gas price volatility could affect our revenues and returns from our trading activities at Enserco, which tend to increase when markets are volatile. |
• | Derivative instruments are used in conjunction with our trading activities to limit a portion of the potential adverse effects resulting from changes in commodity prices and foreign exchange rates. Even though they are closely monitored by Management, our hedging and trading activities can result in losses. Depending upon regulations adopted by the CFTC, we could be required to post additional collateral with our dealer counterparties for our commitments. Such a requirement could have a significant impact on our ability to execute derivative transactions and on cash flow. |
• | The operations of Enserco rely on storage and transportation assets owned by third parties to satisfy their obligations. We depend on pipelines and other storage and transportation facilities owned by third parties to satisfy our delivery obligations under contracts to buy and sell natural gas, crude oil, coal and other commodities, which are settled by physical delivery. |
• | Enserco may be subject to increased regulation, which may limit position limits and opportunity for various transactions. |
• | The global financial situation has affected our counterparty credit risk, and as a consequence the creditworthiness of many of our contractual counterparties (particularly financial institutions) has deteriorated. Additionally, economic conditions may cause increased late payments and uncollectible accounts. Even though we have established guidelines, controls and limits to manage and mitigate credit risk and this is monitored closely by management, to the extent economic conditions cause our credit exposure to contractual counterparties to increase materially, such increased exposure could have a material adverse effect on Energy Marketing's results of operations, liquidity and financial position. |
• | Our inability to obtain required governmental permits and approvals; |
• | Our inability to obtain financing on acceptable terms, or at all; |
• | The possibility that one or more credit rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business; |
• | Our inability to successfully integrate any businesses we acquire; |
• | Our inability to retain management or other key personnel; |
• | Our inability to negotiate acceptable acquisition, construction, fuel supply, power sales or other material agreements; |
• | The trend of utilities building their own generation or looking for developers to develop and build projects for sale to utilities under turnkey arrangements; |
• | Lower than anticipated increases in the demand for utility services in our target markets; |
• | Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves, our oil and gas reserves and our generation capacity; |
• | Fuel prices or fuel supply constraints; |
• | Pipeline capacity and transmission constraints; and |
• | Competition. |
• | Delay in, and restrictions imposed as part of, any required governmental or regulatory approvals; |
• | The loss of management or other key personnel; |
• | The diversion of our management's attention from other business segments; and |
• | Integration and operational issues. |
• | The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals; |
• | Contractual restrictions upon the timing of scheduled outages; |
• | Cost of supplying or securing replacement power during scheduled and unscheduled outages; |
• | The unavailability or increased cost of equipment; |
• | The cost of recruiting and retaining or the unavailability of skilled labor; |
• | Supply interruptions, work stoppages and labor disputes; |
• | Capital and operating costs to comply with increasingly stringent environmental laws and regulations; |
• | Opposition by members of public or special-interest groups; |
• | Weather interferences; |
• | Unexpected engineering, environmental and geological problems; and |
• | Unanticipated cost overruns. |
• | Operational limitations imposed by environmental and other regulatory requirements. |
• | Interruptions to supply of fuel and other commodities used in generation and distribution. The Utilities Group purchases fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather, and environmental regulations, which could limit the Utilities' ability to operate their facilities. |
• | Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak plant. |
• | Inability to recruit and retain skilled technical labor. |
• | Labor relations. Approximately 33% of our employees are represented by a total of six collective bargaining agreements. |
• | Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted, our ability to sell or deliver product and satisfy our contractual obligations may be hindered. |
• | Operating hazards such as leaks, mechanical problems and accidents, including explosions, affecting our natural gas distribution system which could impact public safety, reliability and customer confidence. |
• | We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks and other disruptive activities of individuals or groups. Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities. Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power and by delaying their development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets, and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity. |
• | We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems are vulnerable to disability, failures or unauthorized access, including cyber-attacks. If our technology systems were to fail or be breached and be unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could have material adverse effect on our financial results. |
• | The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources, and could adversely affect our reputation among customers and the public. |
• | A disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system (such as severe weather or a generator or transmission facility outage, pipeline rupture, or a sudden significant increase or decrease in wind generation) within our system or within a neighboring system. Any such disruption could have a material impact on our financial results. |
• | Energy Policy Act of 2005 and the repeal of the PUHCA; |
• | Industry consolidation; |
• | Consumer demands; |
• | Transmission constraints; |
• | Renewable resource supply requirements; |
• | Resistance to the siting of utility infrastructure or to the granting of right-of-ways; |
• | Technological advances; and |
• | Greater availability of natural gas-fired power generation, and other factors. |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
ITEM 3. | LEGAL PROCEEDINGS |
ITEM 5. | MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Year ended December 31, 2011 | ||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||
Dividends paid per share | $ | 0.365 | $ | 0.365 | $ | 0.365 | $ | 0.365 | ||||
Common stock prices | ||||||||||||
High | $ | 33.64 | $ | 34.85 | $ | 32.22 | $ | 34.47 | ||||
Low | $ | 29.76 | $ | 28.12 | $ | 25.83 | $ | 29.10 |
Year ended December 31, 2010 | ||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||
Dividends paid per share | $ | 0.360 | $ | 0.360 | $ | 0.360 | $ | 0.360 | ||||
Common stock prices | ||||||||||||
High | $ | 30.83 | $ | 34.49 | $ | 33.31 | $ | 33.42 | ||||
Low | $ | 25.65 | $ | 27.34 | $ | 27.79 | $ | 29.32 |
Period | Total Number of Shares Purchased * | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs | |||||
October 1, 2011 –October 31, 2011 | — | $ | — | — | — | ||||
November 1, 2011 –November 30, 2011 | 2,772 | $ | 31.27 | — | — | ||||
December 1, 2011 –December 31, 2011 | 4,318 | $ | 32.75 | — | — | ||||
Total | 7,090 | $ | 32.17 | — | — |
* | Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of restricted stock and the exercise of stock options. |
ITEM 6. | SELECTED FINANCIAL DATA |
Years Ended December 31, | 2011 | (1) | 2010 | (1) | 2009 | (1) | 2008 | (1) | 2007 | (1) | ||||||||||
(dollars in thousands, except per share amounts) | ||||||||||||||||||||
Total Assets | $ | 4,127,083 | $ | 3,711,509 | $ | 3,317,698 | $ | 3,379,889 | $ | 2,469,634 | ||||||||||
Property, Plant and Equipment | ||||||||||||||||||||
Total property, plant and equipment | $ | 3,724,016 | $ | 3,353,509 | $ | 2,973,398 | $ | 2,703,117 | $ | 1,845,046 | ||||||||||
Accumulated depreciation and depletion | (934,441 | ) | (861,775 | ) | (812,961 | ) | (681,387 | ) | (507,584 | ) | ||||||||||
Capital Expenditures | $ | 431,707 | $ | 496,990 | $ | 347,819 | $ | 1,304,330 | (2) | $ | 267,047 | |||||||||
Capitalization | ||||||||||||||||||||
Current maturities | $ | 2,473 | $ | 5,181 | $ | 35,245 | $ | 2,078 | $ | 130,326 | ||||||||||
Notes payable | 345,000 | 249,000 | 164,500 | 703,800 | 37,000 | |||||||||||||||
Long-term debt, net of current maturities | 1,280,409 | 1,186,050 | 1,015,912 | 501,252 | 503,301 | |||||||||||||||
Common stock equity | 1,209,336 | 1,100,270 | 1,084,837 | 1,050,536 | 975,022 | |||||||||||||||
Total capitalization | $ | 2,837,218 | $ | 2,540,501 | $ | 2,300,494 | $ | 2,257,666 | $ | 1,645,649 | ||||||||||
Capitalization Ratios | ||||||||||||||||||||
Short-term debt, including current maturities | 12.2 | % | 10.0 | % | 8.7 | % | 31.3 | % | 10.2 | % | ||||||||||
Long-term debt, net of current maturities | 45.1 | % | 46.7 | % | 44.2 | % | 22.2 | % | 30.6 | % | ||||||||||
Common stock equity | 42.7 | % | 43.3 | % | 47.1 | % | 46.5 | % | 59.2 | % | ||||||||||
Total | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||||
Total Operating Revenues (3) | $ | 1,272,188 | $ | 1,219,691 | $ | 1,198,712 | $ | 946,480 | $ | 481,002 | ||||||||||
Net Income Available for Common Stock | ||||||||||||||||||||
Utilities | $ | 81,860 | $ | 74,563 | $ | 57,071 | $ | 43,904 | $ | 31,633 | ||||||||||
Non-regulated Energy | 866 | 10,189 | 1,581 | (5) | (42,384 | ) | (6) | 15,342 | ||||||||||||
Corporate expenses and intersegment eliminations | (42,361 | ) | (4) | (21,611 | ) | (4) | 18,617 | (4) | (76,668 | ) | (4) | (7,878 | ) | |||||||
Income (Loss) from Continuing Operations | 40,365 | 63,141 | 77,269 | (75,148 | ) | 39,097 | ||||||||||||||
Income (loss) from discontinued operations, net of tax (7) | 9,365 | 5,544 | 4,286 | 180,358 | 60,052 | |||||||||||||||
Net loss attributable to non-controlling interest | — | — | — | (130 | ) | (377 | ) | |||||||||||||
Net income available for common stock | $ | 49,730 | $ | 68,685 | $ | 81,555 | $ | 105,080 | $ | 98,772 | ||||||||||
Years Ended December 31, | 2011 | (1) | 2010 | (1) | 2009 | (1) | 2008 | (1) | 2007 | (1) | ||||||||||
(dollars in thousands, except per share amounts) | ||||||||||||||||||||
Dividends Paid on Common Stock | $ | 59,202 | $ | 56,467 | $ | 55,151 | $ | 53,663 | $ | 50,300 | ||||||||||
Common Stock Data(8) (in thousands) | ||||||||||||||||||||
Shares outstanding, average | 39,864 | 38,916 | 38,614 | 38,193 | 37,024 | |||||||||||||||
Shares outstanding, average diluted | 40,081 | 39,091 | 38,684 | 38,193 | 37,414 | |||||||||||||||
Shares outstanding, end of year | 43,925 | 39,269 | 38,969 | 38,636 | 37,796 | |||||||||||||||
Earnings (Loss) Per Share of Common Stock (in dollars) (8) | ||||||||||||||||||||
Basic earnings (loss) per average share - | ||||||||||||||||||||
Continuing operations | $ | 1.01 | $ | 1.62 | $ | 2.00 | $ | (1.97 | ) | $ | 1.06 | |||||||||
Discontinued operations | 0.24 | 0.14 | 0.11 | 4.72 | 1.61 | |||||||||||||||
Non-controlling interest | — | — | — | — | (0.01 | ) | ||||||||||||||
Total | $ | 1.25 | $ | 1.76 | $ | 2.11 | $ | 2.75 | $ | 2.66 | ||||||||||
Diluted earnings (loss) per average share - | ||||||||||||||||||||
Continuing operations | $ | 1.01 | $ | 1.62 | $ | 2.00 | $ | (1.95 | ) | $ | 1.04 | |||||||||
Discontinued operations | 0.23 | 0.14 | 0.11 | 4.72 | 1.61 | |||||||||||||||
Non-controlling interest | — | — | — | — | (0.01 | ) | ||||||||||||||
Total | $ | 1.24 | $ | 1.76 | $ | 2.11 | $ | 2.77 | $ | 2.64 | ||||||||||
Dividends Declared per Share | $ | 1.46 | $ | 1.44 | $ | 1.42 | $ | 1.40 | $ | 1.37 |
Book Value Per Share, End of Year | $ | 27.55 | $ | 28.02 | $ | 27.84 | $ | 27.19 | $ | 25.66 | ||||||||||
Return on Average Common Stock Equity (year-end) | 4.3 | % | 6.3 | % | 7.6 | % | 10.4 | % | 11.2 | % | ||||||||||
Years ended December 31, | 2011 | 2010 | 2009 | 2008 | 2007 | |||||||||
Operating Statistics: | ||||||||||||||
Generating capacity (MW): | ||||||||||||||
Electric Utilities (owned generation) (9) | 865 | 687 | 630 | 630 | 435 | |||||||||
Electric Utilities (purchased capacity) | 450 | 440 | 430 | 420 | 50 | |||||||||
Power Generation (owned generation) (9) (10) | 309 | 120 | 120 | 141 | 983 | |||||||||
Total generating capacity | 1,624 | 1,247 | 1,180 | 1,191 | 1,468 | |||||||||
Electric Utilities: | ||||||||||||||
MWh sold:(1) | ||||||||||||||
Retail electric | 4,590,800 | 4,532,191 | 4,403,459 | 3,532,402 | 2,552,290 | |||||||||
Contracted wholesale | 349,520 | 468,782 | 645,297 | 665,795 | 647,444 | |||||||||
Wholesale off-system | 1,788,005 | 1,749,524 | 1,692,191 | 1,551,273 | 942,045 | |||||||||
Total MWh sold | 6,728,325 | 6,750,497 | 6,740,947 | 5,749,470 | 4,141,779 | |||||||||
Gas Utilities:(1) (11) | ||||||||||||||
Gas sold (Dth) | 55,764,154 | 55,265,630 | 56,671,438 | 23,053,599 | — | |||||||||
Transport volumes (Dth) | 59,216,132 | 59,879,450 | 55,104,284 | 26,805,075 | — | |||||||||
Oil and gas production sold (MMcfe) | 11,762 | 11,300 | 12,463 | 13,534 | 14,627 | |||||||||
Oil and gas reserves (MMcfe) | 133,242 | 131,096 | 119,304 | 185,542 | 199,092 | |||||||||
Tons of coal sold (thousands of tons) | 5,692 | 5,931 | 5,955 | 6,017 | 5,049 | |||||||||
Coal reserves (thousands of tons) | 256,170 | 261,860 | 268,000 | 274,000 | 280,000 | |||||||||
Discontinued Operations: | ||||||||||||||
Average daily marketing volumes:- | ||||||||||||||
Natural gas physical sales (MMBtu) | 1,524,000 | 1,586,000 | 1,974,300 | 1,873,400 | 1,743,500 | |||||||||
Crude oil physical sales (Bbls) | 24,775 | 18,455 | 12,400 | 7,880 | 8,600 | |||||||||
Coal physical sales (Tons)(12) | 35,300 | 33,250 | — | — | — | |||||||||
Power (MWh) (12) | 265 | — | — | — | — | |||||||||
Environmental (12) | — | — | — | — | — |
(1) | All years have been restated to include our Energy Marketing segment in Discontinued Operations. 2008 includes electric and gas utilities acquired on July 14, 2008. |
(2) | Includes $938.4 million for the Aquila acquisition. |
(3) | Revenues have been restated to reflect elimination of certain inter-company transactions with our rate regulated operations (see Note 1 of the Notes to the Consolidated Financial Statements of this Annual Report on Form 10-K). |
(4) | 2011, 2010 and 2008 include a $27.3 million, a $9.9 million and a $61.4 million, after-tax unrealized non-cash mark-to-market loss, respectively, related to certain interest rate swaps; while 2009 includes a $36.2 million after-tax unrealized non-cash mark-to-market gain related to certain interest rate swaps. |
(5) | Includes a $27.8 million after-tax non-cash ceiling test impairment charge to our crude oil and natural gas properties taken in 2009 and a $16.9 million after-tax gain on sale of 23.5% ownership interest in Wygen I. |
(6) | Includes a $59.0 million after-tax non-cash ceiling test impairment charge to our crude oil and natural gas properties taken in 2008. |
(7) | Discontinued operations include the operations of the Energy Marketing segment in 2011, 2010, 2009, 2008 and 2007, and the assets sold in the IPP Transaction for 2009, 2008 and 2007. |
(8) | During November 2011, we issued 4.4 million shares of common stock and during February 2007, we issued 4.2 million shares of common stock, which diluted our earnings per share in subsequent periods. |
(9) | The PPA between Colorado Electric and Black Hills Colorado IPP is accounted for as a capital lease. This table reflects owned capacity by the Electric Utilities and Power Generation. |
(10) | 2007 includes 825 MW which have been reported as "Discontinued operations." |
(11) | Excludes Cheyenne Light. |
ITEMS 7 & | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS |
and 7A. | OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET |
Business Group | Financial Segment |
Utilities | Electric Utilities |
Gas Utilities | |
Non-regulated Energy * | Oil and Gas |
Power Generation | |
Coal Mining |
* | In January 2012, we entered into a Stock Purchase Agreement to sell Enserco, our Energy Marketing segment, which resulted in the reporting of this segment as discontinued operations. The sale transaction is expected to be completed during the first quarter of 2012. |
• | In states such as South Dakota and Wyoming that currently have no legislative mandate on the use of renewable energy, we have proactively integrated cost-effective renewable energy into our generation supply based upon our expectation that there will be mandatory renewable energy standards in the future. For example, under two 20-year PPAs we purchase a total of 60 MW of wind energy from wind farms located near Cheyenne, Wyoming for use at Black Hills Power and Cheyenne Light; |
• | Colorado and Montana have legislative mandates regarding the use of renewable energy. Therefore, we aggressively pursue cost-effective initiatives with the regulators that will allow us to meet our renewable energy requirements. To the extent practical, we intend to construct renewable generation resources as rate base assets, which will help mitigate the long-term customer rate impact of adding renewable energy supplies. For example, the CPUC approved a 29 MW wind turbine project in which we are permitted to rate base 50% ownership as part of our plan to meet Colorado's Renewable Energy Standard expected to be completed by the end of 2012; and |
• | In all states in which we conduct electric utility operations, we are exploring other potential biomass, solar and wind energy projects, particularly wind generation sites located near our utility service territories. |
• | Through detailed reservoir analysis, apply proven technologies to our existing assets to maximize value; |
• | Participate in a limited number of selective and meaningful exploration prospects; |
• | Primarily focus on the Rocky Mountain region, where we can more easily integrate new opportunities with our existing crude oil and natural gas operations as well as our power generation activities. Specifically, we intend to focus our near term efforts on fully developing the substantial shale gas potential of our San Juan and Piceance Basin properties, continuing our participation in the Bakken oil shale play and participating in select oil exploration prospects with substantial upside opportunities; |
• | Support the future capital requirements of our drilling program by stabilizing cash flows with a hedging program that mitigates commodity price risk for a portion of our established production for up to two years in the future; and |
• | Enhance our crude oil and natural gas production activities with the construction or acquisition of mid-stream gathering, compression and treating facilities in a manner that maximizes the economic value of our operations. |
• | Cheyenne Light and Black Hill Power filed a joint CPCN requesting approval to construct a new 132 MW generating facility; |
• | Colorado Electric completed construction of a 180 MW generating facility, which was placed into commercial operation on January 1, 2012; |
• | Although CPUC issued an order approving the retirement of our W.N. Clark coal-fired generation facility in order to comply with the Colorado Clean Air-Clean Jobs Act for Colorado Electric, the CPUC has not yet approved plans proposed to replace the facility; and |
• | The CPUC approved construction of a 29 MW wind farm, of which Colorado Electric will own 50%, as part of our plan to meet Colorado's Renewable Energy Standards and Colorado Electric expects to file an energy resource plan to address additional renewable energy required to comply with Colorado's renewable energy standards in the second quarter of 2012. |
For the Years Ended | For the Years Ended | ||||||||||||||||||
2011 | 2010 | Increase (Decrease) | 2010 | 2009 | Increase (Decrease) | ||||||||||||||
(in thousands) | |||||||||||||||||||
Revenue (a) | |||||||||||||||||||
Utilities | $ | 1,168,915 | $ | 1,120,721 | $ | 48,194 | $ | 1,120,721 | $ | 1,101,077 | $ | 19,644 | |||||||
Non-regulated Energy | 178,372 | 162,355 | 16,017 | 162,355 | 159,749 | 2,606 | |||||||||||||
Intercompany eliminations | (75,099 | ) | (63,385 | ) | (11,714 | ) | (63,385 | ) | (62,114 | ) | (1,271 | ) | |||||||
$ | 1,272,188 | $ | 1,219,691 | $ | 52,497 | $ | 1,219,691 | $ | 1,198,712 | $ | 20,979 | ||||||||
Income (loss) from continuing operations | |||||||||||||||||||
Electric Utilities | $ | 47,691 | $ | 47,452 | $ | 239 | $ | 47,452 | $ | 32,699 | $ | 14,753 | |||||||
Gas Utilities | 34,169 | 27,111 | 7,058 | 27,111 | 24,372 | 2,739 | |||||||||||||
Utilities | 81,860 | 74,563 | 7,297 | 74,563 | 57,071 | 17,492 | |||||||||||||
Oil and Gas | (1,721 | ) | 357 | (2,078 | ) | 357 | (25,828 | ) | 26,185 | ||||||||||
Power Generation | 3,011 | 2,151 | 860 | 2,151 | 20,661 | (18,510 | ) | ||||||||||||
Coal Mining | (424 | ) | 7,681 | (8,105 | ) | 7,681 | 6,748 | 933 | |||||||||||
Non-regulated Energy | 866 | 10,189 | (9,323 | ) | 10,189 | 1,581 | 8,608 | ||||||||||||
Corporate and Eliminations (b) | (42,361 | ) | (21,611 | ) | (20,750 | ) | (21,611 | ) | 18,617 | (40,228 | ) | ||||||||
Income from continuing operations | 40,365 | 63,141 | (22,776 | ) | 63,141 | 77,269 | (14,128 | ) | |||||||||||
Income (loss) from discontinued operations, net of tax (c) | 9,365 | 5,544 | 3,821 | 5,544 | 4,286 | 1,258 | |||||||||||||
Net income (loss) | $ | 49,730 | $ | 68,685 | $ | (18,955 | ) | $ | 68,685 | $ | 81,555 | $ | (12,870 | ) |
(a) | 2010 revenue has been restated to eliminate certain inter-company revenue previously not eliminated. This change did not have an impact on our gross margin or net income. See Note 1 of the Consolidated Financial Statements in this Annual Report on Form 10-K. |
(b) | Financial results of Enserco, our Energy Marketing segment, have been reclassified as discontinued operations in accordance with GAAP. When preparing this reclassification, certain indirect corporate costs and inter-segment interest expenses previously charged to our Energy Marketing segment could not be reclassified to discontinued operations and accordingly have been presented within Corporate. See Note 23 of the Consolidated Financial Statements in this Annual Report on Form 10-K. |
(c) | Income (loss) from discontinued operations, net of tax includes the activities of Enserco, our Energy Marketing segment, for 2011, 2010 and 2009 and the IPP Transaction for 2009. See Note 23 of the Consolidated Financial Statements in this Annual Report on Form 10-K. |
• | Our return on investments made in the Utilities Group was positively impacted by new and interim rates and tariffs implemented in five utility jurisdictions during 2010. Consequently, year-to-date revenues have been positively impacted for rates that were not in effect in the prior periods. |
Utility | State | Effective Date | Annual Revenue Increase (in millions) | |||
Black Hills Power | SD | 4/2010 | $ | 15.2 | ||
Black Hills Power | WY | 6/2010 | $ | 3.1 | ||
Colorado Electric | CO | 8/2010 | $ | 17.9 | ||
Nebraska Gas | NE | 3/2010 | $ | 8.3 | ||
Iowa Gas | IA | 6/2010 | $ | 3.4 | ||
$ | 47.9 |
• | Construction of gas-fired generation to serve Colorado Electric customers was completed and the plant was placed in service on January 1, 2012. The 180 MW generation project cost approximately $230 million; |
• | On April 28, 2011, Colorado Electric filed a request with the CPUC for a revenue increase of $40.2 million to recover costs and a return associated with the 180 MW generation project and other utility infrastructure assets and expenses, including PPA costs associated with the 200 MW Colorado IPP generation facility. On December 22, 2011, the CPUC issued an order approving an annual base rate increase of $10.5 million with a rate of return ranging from 9.8% to 10.2% with a capital structure of 49.1% equity and 50.9% debt. The CPUC approved additional costs to be recovered through rate adjustment mechanisms of approximately $17.5 million. New rates were effective January 1, 2012; |
• | On December 1, 2011, Cheyenne Light filed requests for electric and natural gas revenue increases with the WPSC to recover investments in infrastructure and other costs. Cheyenne Light is seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue; |
• | On November 1, 2011, Cheyenne Light and Black Hills Power filed a joint request with the WPSC for a certificate of public convenience and necessity to construct and operate a new $237 million natural gas-fired electric generation facility and related gas and electric transmission in Cheyenne, WY. The proposed facility will include construction of one simple-cycle, 37 MW combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 MW unit that will be jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Light will own 40 MW and Black Hills Power will own 55 MW of the combined cycle unit. Pending WPSC approval, commercial operation would commence in 2014. A hearing with the WPSC is scheduled in July 2012; |
• | In June 2011, the SDPUC approved an Environmental Improvement Adjustment tariff for Black Hills Power. The Environmental Improvement Adjustment, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect on June 1, 2011 with an annual revenue increase of $3.1 million; |
• | On August 12, 2011, Colorado Electric received approval from the CPUC to rate base 50% ownership in a 29 MW wind turbine project as part of its plan to meet Colorado's Renewable Energy Standard. The CPUC authorized us to conduct a competitive solicitation for ownership of the other 50% of the project under which a partner was selected in December 2011 and a Renewable Energy Purchase Agreement and Participation agreement was executed on December 22, 2011. Colorado Electric's share of this project is expected to cost approximately $26.5 million. It is expected to begin serving Colorado Electric customers no later than December 31, 2012; and |
• | On March 14, 2011, Colorado Electric filed a request for a CPCN to construct a third utility-owned 88 MW natural gas-fired turbine with an approximate cost of $102.0 million, excluding transmission. This CPCN request was filed in accordance with a December 2010 CPUC order. This order approved the retirement of the W.N. Clark coal-fired power plant under the Colorado Clean Air-Clean Jobs Act and granted a presumption of need for a portion of a third utility-owned turbine at the Pueblo Airport Generation Station. A settlement with some of the intervenors was reached and a settlement hearing occurred on October 25, 2011. On December 14, 2011, an administrative law judge issued a recommendation to deny Colorado Electric's request and the terms of the settlement agreement. Colorado Electric submitted an exception filing on January 10, 2012, and an initial decision from the CPUC is expected in mid-2012. |
• | In January 2012, we entered into a definitive agreement to sell the outstanding stock of Enserco Energy, Inc., our Energy Marketing segment. Net cash proceeds are expected to total approximately $160 million to $170 million, subject to working capital and other closing adjustments. The sale is subject to customary regulatory approvals and is expected to close in the first quarter of 2012. The activities of the Energy Marketing segment have been reclassified to discontinued operations; |
• | Construction of gas-fired generation at Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric was completed and the plant was placed into commercial operations on January 1, 2012. The 200 MW project cost approximately $261 million; |
• | Three test wells as part of our Oil and Gas segment's Mancos shale horizontal drilling program in the San Juan and Piceance Basins have been completed and are on production. Production test results and reserve estimates are encouraging; and |
• | In January 2011, we sold our ownership interests in the partnerships that owned the Idaho generating facilities for $0.8 million and recorded a gain of $0.8 million. |
• | We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $42.0 million in 2011 compared to a $15.2 million unrealized mark-to-market loss on these swaps for the same period in 2010; |
• | In November 2011, the Equity Forward Agreements were settled by issuing 4,413,519 shares of Black Hills Corporation common stock in return for net cash proceeds of $119.6 million; |
• | In September 2011, we extended our $100.0 million term loan under the existing terms for two years; and |
• | In June 2011, we entered into a $150 million one year, unsecured, single draw, term loan. The cost of borrowing under this term loan is based on a spread of 1.25% over LIBOR. |
• | Our return on investments made in the Utilities Group was positively impacted by new and interim rates and tariffs implemented in five utility jurisdictions during 2010. Consequently, year-to-date revenues were positively impacted for rates that were not in effect in the prior periods. |
Utility | State | Effective Date | Annual Revenue Increase (in millions) | |||
Black Hills Power | SD | 4/2010 | $ | 15.2 | ||
Black Hills Power | WY | 6/2010 | $ | 3.1 | ||
Colorado Electric | CO | 8/2010 | $ | 17.9 | ||
Nebraska Gas | NE | 3/2010 | $ | 8.3 | ||
Iowa Gas | IA | 6/2010 | $ | 3.4 | ||
$ | 47.9 |
• | Construction of a 180 MW gas-fired generation to serve Colorado Electric customers moved forward to start providing energy by January 1, 2012. Expenditures were approximately $164.4 million through December 31, 2010; |
• | The Wygen III generating facility commenced commercial operations on April 1, 2010. In July 2010, Black Hills Power sold a 23% ownership interest in the Wygen III power generation facility to the City of Gillette for $62.0 million. A gain of $6.2 million was recognized on the sale; |
• | On October 1, 2010, Black Hills Power suspended the operations of its 62 year old, 34.5 MW coal-fired Osage Power Plant located in Osage, Wyoming. We now have more economical power supply alternatives available to provide for present customer energy demands; however, the plant's operating permits have been retained so that full operations can be restored if needed; |
• | Our Electric Utilities reached agreement with the DOE for smart grid funding through matching grants totaling $20.7 million, made available through the American Recovery and Reinvestment Act of 2009. As of December 31, 2010, we have completed 100% of the installations related to these meters; |
• | Due to the annexation of an outlying suburb by the City of Omaha, NE, we sold assets serving approximately 3,000 customers to Metropolitan Utilities District on March 2, 2010. We received $6.1 million in cash and recognized a $2.7 million gain on the sale in the first quarter of 2010; and |
• | In December 2010, Colorado Electric received a final order from the CPUC regarding its plan to comply with the Colorado Clean Air, Clean Jobs Act. The order approved the retirement of the utility's 42 MW W.N. Clark coal-fired generation facility and granted a presumption of need for replacement of the plant. The utility proposed to construct a third 88 MW natural gas-fired turbine at the site of our Pueblo Airport Generation Station. |
• | Construction of a 200 MW gas-fired generation at Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric moved forward to start providing energy by January 1, 2012. Expenditures on the project were $162.6 million through December 31, 2010; |
• | The first quarter of 2009 included a $16.9 million after-tax gain at our Power Generation segment on the sale to MEAN of a 23.5% ownership interest in the Wygen I power generation facility; and |
• | The first quarter of 2009 included a $27.8 million after-tax non-cash ceiling test impairment charge due to a write-down in value of our natural gas and crude oil properties resulting from low quarter-end prices for the commodities at our Oil and Gas segment. |
• | We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $15.2 million in 2010 compared to a $55.7 million unrealized gain on these swaps for the same period in 2009; |
• | In April 2010, we entered into a new three-year $500 million Revolving Credit Facility. The Revolving Credit Facility will be used to fund working capital needs and other corporate purposes; |
• | In July 2010, we completed a public offering of $200 million aggregate principal amount of senior unsecured notes due July 15, 2020. The notes were priced at par and carry an interest rate of 5.875%; |
• | In November 2010, we entered into an equity forward offering for 4,000,000 shares. In December 2010, the underwriters exercised their over-allotment option and purchased 413,519 additional shares. We settled the equity forward instruments in November 2011; |
• | In December 2010, we entered into a $100 million unsecured one-year term loan. The cost of borrowings under the loan is based on a spread of 1.375% over LIBOR; and |
• | We recorded a $2.4 million reduction in tax expense reflecting a re-measurement of a tax position in accordance with accounting for uncertain tax positions. Approximately $2.0 million of this benefit was recorded in the Corporate segment. The re-measurement was prompted by a settlement agreement that was reached with the IRS Appeals Division primarily regarding tax depreciation method changes. |
2011 | 2010 | 2009 | |||||||
Revenue - electric | $ | 577,513 | $ | 532,423 | $ | 485,152 | |||
Revenue - Cheyenne Light gas | 36,818 | 37,591 | 35,613 | ||||||
Total revenue | 614,331 | 570,014 | 520,765 | ||||||
Fuel and purchased power - electric | 288,354 | 269,747 | 260,150 | ||||||
Purchased gas - Cheyenne Light | 21,998 | 23,064 | 20,859 | ||||||
Total fuel and purchased power | 310,352 | 292,811 | 281,009 | ||||||
Gross margin - electric | 289,159 | 262,676 | 225,002 | ||||||
Gross margin - Cheyenne Light gas | 14,820 | 14,527 | 14,754 | ||||||
Total gross margin | 303,979 | 277,203 | 239,756 | ||||||
Operations and maintenance | 142,815 | 136,873 | 125,150 | ||||||
Gain on sale of operating asset | (768 | ) | (6,238 | ) | — | ||||
Depreciation and amortization | 52,475 | 47,276 | 43,638 | ||||||
Total operating expenses | 194,522 | 177,911 | 168,788 | ||||||
Operating income | 109,457 | 99,292 | 70,968 | ||||||
Interest expense, net | 38,976 | 37,043 | 33,012 | ||||||
Other income, net | (481 | ) | (3,215 | ) | (7,869 | ) | |||
Income tax expense | 23,271 | 18,012 | 13,126 | ||||||
Income from continuing operations | $ | 47,691 | $ | 47,452 | $ | 32,699 |
2011 | 2010 | 2009 | ||||
Regulated power plant fleet availability: | ||||||
Coal-fired plants (a) | 91.3 | % | 93.9 | % | 92.1 | % |
Other plants | 96.4 | % | 96.2 | % | 96.9 | % |
Total availability | 93.1 | % | 94.8 | % | 94.0 | % |
(a) | 2011 reflects a major overhaul and an unplanned outage at the PacifiCorp-operated Wyodak plant. |
2011 | 2010 | 2009 | |||||||
Revenue: | |||||||||
Natural gas - regulated | $ | 526,972 | $ | 520,691 | $ | 553,576 | |||
Other - non-regulated | 27,612 | 30,016 | 26,736 | ||||||
Total revenue | 554,584 | 550,707 | 580,312 | ||||||
Cost of sales: | |||||||||
Natural gas - regulated | 317,257 | 316,546 | 356,623 | ||||||
Other - non-regulated | 14,704 | 17,171 | 15,093 | ||||||
Total cost of sales | 331,961 | 333,717 | 371,716 | ||||||
Gross margin: | |||||||||
Natural gas - regulated | 209,715 | 204,145 | 196,953 | ||||||
Other non-regulated | 12,908 | 12,845 | 11,643 | ||||||
Total gross margin | 222,623 | 216,990 | 208,596 | ||||||
Operations and maintenance | 121,980 | 125,447 | 123,296 | ||||||
Gain on sale of operating assets | — | (2,683 | ) | — | |||||
Depreciation and amortization | 24,307 | 25,258 | 30,090 | ||||||
Total operating expenses | 146,287 | 148,022 | 153,386 | ||||||
Operating income | 76,336 | 68,968 | 55,210 | ||||||
Interest expense, net | 25,976 | 27,455 | 17,100 | ||||||
Other expense (income), net | (217 | ) | (47 | ) | 285 | ||||
Income tax expense | 16,408 | 14,449 | 13,453 | ||||||
Income from continuing operations | $ | 34,169 | $ | 27,111 | $ | 24,372 |
2011 | 2010 | 2009 | |||||||
Revenue | $ | 79,808 | $ | 74,164 | $ | 70,684 | |||
Operations and maintenance | 41,380 | 39,299 | 40,224 | ||||||
Depreciation, depletion and amortization | 35,690 | 30,283 | 29,680 | ||||||
Impairment of long-lived assets | — | — | 43,301 | ||||||
Total operating expenses | 77,070 | 69,582 | 113,205 | ||||||
Operating income (loss) | 2,738 | 4,582 | (42,521 | ) | |||||
Interest expense, net | 5,894 | 5,372 | 4,673 | ||||||
Other (income) expense, net | 216 | (722 | ) | (350 | ) | ||||
Income tax (benefit) expense | (1,651 | ) | (425 | ) | (21,016 | ) | |||
Income (loss) from continuing operations | $ | (1,721 | ) | $ | 357 | $ | (25,828 | ) |
Crude Oil and Natural Gas Production | 2011 | 2010 | 2009 | |||
Bbls of oil sold | 451,823 | 375,646 | 366,000 | |||
Mcfe of natural gas sold | 9,051,393 | 9,046,493 | 10,266,900 | |||
Mcf equivalent sales | 11,762,331 | 11,300,369 | 12,462,900 |
Average Price Received (a) | 2011 | 2010 | 2009 | ||||||
Gas/Mcf(b) | $ | 4.29 | $ | 4.85 | $ | 4.71 | |||
Oil/Bbl | $ | 79.74 | $ | 75.59 | $ | 59.19 |
(a) | Net of hedge settlement gains/losses |
(b) | Exclusive of gas liquids |
2011 | 2010 | 2009 | |||||||
Depletion expense/Mcfe* | $ | 2.76 | $ | 2.36 | $ | 2.16 |
* | The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The increased depletion rate in 2011 is primarily driven by the high cost of wells associated with our drilling activities in the Bakken shale formation. The 2009 rate was particularly impacted by a lower asset base as a result of previous asset impairment charges. This impact was partially offset by persistent low product prices during the year, which resulted in lower oil and gas reserve quantities. |
2011 | ||||||||||||
LOE | Gathering Compression and Processing | Production Taxes | Total | |||||||||
San Juan | $ | 1.09 | $ | 0.35 | $ | 0.49 | $ | 1.93 | ||||
Piceance | 0.79 | 0.76 | 0.11 | 1.66 | ||||||||
Powder River | 1.37 | — | 1.29 | 2.66 | ||||||||
Williston | 0.79 | — | 1.55 | 2.34 | ||||||||
All other properties | 1.06 | — | 0.27 | 1.33 | ||||||||
Total | $ | 1.07 | $ | 0.23 | $ | 0.70 | $ | 2.00 |
2010 | ||||||||||||
LOE | Gathering Compression and Processing | Production Taxes | Total | |||||||||
San Juan | $ | 1.30 | $ | 0.34 | $ | 0.54 | $ | 2.18 | ||||
Piceance | 0.68 | 0.64 | (0.09 | ) | 1.23 | |||||||
Powder River | 1.20 | — | 1.02 | 2.22 | ||||||||
Williston | 0.92 | — | 1.03 | 1.95 | ||||||||
All other properties | 0.92 | — | 0.25 | 1.17 | ||||||||
Total | $ | 1.13 | $ | 0.22 | $ | 0.55 | $ | 1.90 |
2009 | ||||||||||||
LOE | Gathering Compression and Processing | Production Taxes | Total | |||||||||
San Juan | $ | 1.27 | $ | 0.28 | $ | 0.47 | $ | 2.02 | ||||
Piceance | 1.06 | 0.41 | 0.25 | 1.72 | ||||||||
Powder River | 1.36 | — | 0.72 | 2.08 | ||||||||
Williston | 0.67 | — | 0.88 | 1.55 | ||||||||
All other properties | 1.08 | 0.04 | 0.25 | 1.37 | ||||||||
Total | $ | 1.22 | $ | 0.18 | $ | 0.46 | $ | 1.86 |
2011 | 2010 | 2009 | ||||
Bbls of oil (in thousands) | 6,223 | 5,940 | 5,274 | |||
MMcf of natural gas | 95,904 | 95,456 | 87,660 | |||
Total MMcfe | 133,242 | 131,096 | 119,304 |
2011 | 2010 | 2009 | |||||||||||||||||||||
Oil | Gas | Oil | Gas | Oil | Gas | ||||||||||||||||||
NYMEX prices | $ | 96.19 | $ | 4.12 | $ | 79.43 | $ | 4.38 | $ | 61.18 | $ | 3.87 | |||||||||||
Well-head reserve prices | $ | 88.49 | $ | 3.59 | $ | 70.82 | $ | 3.45 | $ | 53.59 | $ | 2.52 |
2011 | 2010 | 2009 | |||||||
Revenue | $ | 31,672 | $ | 30,349 | $ | 30,575 | |||
Operations and maintenance | 16,538 | 16,210 | 12,631 | ||||||
Depreciation and amortization | 4,199 | 4,466 | 3,860 | ||||||
Gain on sale of operating assets | — | — | (25,971 | ) | |||||
Total operating expenses | 20,737 | 20,676 | (9,480 | ) | |||||
Operating income | 10,935 | 9,673 | 40,055 | ||||||
Interest expense, net | 7,374 | 8,110 | 9,388 | ||||||
Other (income) expense, net | (1,094 | ) | (854 | ) | (1,091 | ) | |||
Income tax expense | 1,644 | 266 | 11,097 | ||||||
Income from continuing operations | $ | 3,011 | $ | 2,151 | $ | 20,661 |
2011 | 2010 | 2009 | ||||
Independent power capacity: | ||||||
MW of independent power capacity in service | 309 | 120 | 120 | |||
Contracted fleet plant availability: | ||||||
Gas-fired plants | 98.4 | % | 99.9 | % | 92.0 | % |
Coal-fired plants | 100.0 | % | 98.5 | % | 96.1 | % |
Total | 99.0 | % | 99.1 | % | 94.4 | % |
2011 | 2010 | 2009 | |||||||
Revenue | $ | 66,892 | $ | 57,842 | $ | 58,490 | |||
Operations and maintenance | 56,617 | 34,028 | 40,312 | ||||||
Depreciation, depletion and amortization | 18,670 | 19,083 | 13,123 | ||||||
Total operating expenses | 75,287 | 53,111 | 53,435 | ||||||
Operating income (loss) | (8,395 | ) | 4,731 | 5,055 | |||||
Interest income, net | (3,888 | ) | (3,180 | ) | (1,452 | ) | |||
Other income, net | (2,192 | ) | (2,149 | ) | (3,475 | ) | |||
Income tax expense | (1,891 | ) | 2,379 | 3,234 | |||||
Income (loss) from continuing operations | $ | (424 | ) | $ | 7,681 | $ | 6,748 |
2011 | 2010 | 2009 | ||||
Tons of coal sold | 5,692 | 5,931 | 5,955 | |||
Cubic yards of overburden moved | 14,735 | 15,679 | 14,539 | |||
Coal reserves at year-end | 256,170 | 261,860 | 268,000 |
• | We incurred a $42.0 million unrealized mark-to-market loss in 2011 related to certain interest rate swaps that are no longer designated as hedges for accounting purposes compared to a $15.2 million unrealized mark-to-market loss in 2010; and |
• | Corporate was allocated costs of $3.4 million originally allocated to our Energy Marketing segment in 2011 which could not be included in discontinued operations compared to $3.5 million in 2010. |
• | We incurred a $15.2 million unrealized mark-to-market loss in 2010 related to certain interest rate swaps that are no longer designated as hedges for accounting purposes compared to an unrealized mark-to-market gain of $55.7 million in 2009; |
• | Net interest expense increased $1.4 million primarily due to interest settlements of the de-designated interest rate swaps; |
• | The effective tax rate for 2010 was favorably impacted due to a re-measurement of a previously recorded uncertain tax position prompted by a settlement agreement with the IRS relating primarily to depreciation method changes; and |
• | Corporate was allocated costs of $3.5 million originally allocated to our Energy Marketing segment in 2010 which could not be included in discontinued operations compared to $3.8 million in 2009. |
Gross margins by commodity: | For the Years Ended December 31, | |||||||||||||||||
Natural Gas | Crude Oil | Coal | Power | Environmental | Total | |||||||||||||
2011 | ||||||||||||||||||
Realized | $ | 21,416 | $ | 22,793 | $ | 1,148 | $ | (1,271 | ) | $ | (13 | ) | $ | 44,073 | ||||
Unrealized | (10,268 | ) | (2,756 | ) | 3,298 | 6,664 | 90 | (2,972 | ) | |||||||||
Total | $ | 11,148 | $ | 20,037 | $ | 4,446 | $ | 5,393 | $ | 77 | $ | 41,101 | ||||||
Natural Gas | Crude Oil | Coal(a) | Power(a) | Environmental(a) | Total | |||||||||||||
2010 | ||||||||||||||||||
Realized | $ | 24,536 | $ | 8,888 | $ | 1,541 | $ | (2,467 | ) | $ | — | $ | 32,498 | |||||
Unrealized | (6,777 | ) | 1,663 | 2,012 | (1,397 | ) | — | (4,499 | ) | |||||||||
Total | $ | 17,759 | $ | 10,551 | $ | 3,553 | $ | (3,864 | ) | $ | — | $ | 27,999 | |||||
Natural Gas | Crude Oil | Coal(a) | Power(a) | Environmental(a) | Total | |||||||||||||
2009 | ||||||||||||||||||
Realized | $ | 30,134 | $ | 11,278 | $ | — | $ | — | $ | — | $ | 41,412 | ||||||
Unrealized | (19,777 | ) | (8,254 | ) | — | — | — | (28,031 | ) | |||||||||
Total | $ | 10,357 | $ | 3,024 | $ | — | $ | — | $ | — | $ | 13,381 |
(a) | Activity of Coal marketing commenced June 1, 2010 and Power and Environmental marketing commenced late in the third quarter of 2010. |
Change in Assumed Trend Rate | Impact on December 31, 2011 Accumulated Postretirement Benefit Obligation | Impact on 2011 Service and Interest Cost | ||||||
Increase 1% | $ | 2,720 | $ | 184 | ||||
Decrease 1% | $ | (2,272 | ) | $ | (150 | ) |
Financial Position Summary | 2011 | 2010 | ||||
Cash and cash equivalents | $ | 21,628 | $ | 16,437 | ||
Restricted cash | $ | 9,254 | $ | 4,260 | ||
Short-term debt, including current maturities of long-term debt | $ | 347,473 | $ | 254,181 | ||
Long-term debt | $ | 1,280,409 | $ | 1,186,050 | ||
Stockholders' equity | $ | 1,209,336 | $ | 1,100,270 | ||
Ratios | ||||||
Long-term debt ratio | 51.4 | % | 51.9 | % | ||
Total debt ratio | 57.4 | % | 56.7 | % |
Current | Borrowings at | Letters of Credit at | Available Capacity at | ||||||||||
Credit Facility | Expiration | Capacity | December 31, 2011 | December 31, 2011 | December 31, 2011 | ||||||||
Revolving Credit Facility * | April 14, 2013 | $ | 500.0 | $ | 195.0 | $ | 43.7 | $ | 261.3 |
* | The Revolving Credit Facility was replaced when we entered into a new Revolving Credit Facility on February 1, 2012. See Credit Facilities and Long-Term Debt below. |
2011 | 2010 | ||||||
Utility cash collateral requirements | $ | 19,416 | $ | 10,355 | |||
Letters of credit on Revolving Credit Facility | 43,700 | 46,865 | |||||
Total Funds on Deposit | $ | 63,116 | $ | 57,220 |
Borrowings From (Loans To) Money Pool Outstanding | ||||||
2011 | 2010 | |||||
Subsidiary: | ||||||
Black Hills Utility Holdings | $ | 273,063 | $ | 168,867 | ||
Black Hills Power | (50,477 | ) | (39,454 | ) | ||
Cheyenne Light | (15,208 | ) | (14,527 | ) | ||
Total Money Pool borrowings from Parent | $ | 207,378 | $ | 114,886 |
Rating Agency | Rating | Outlook |
Moody's | Baa3 | Stable |
S&P | BBB- | Stable |
Fitch | BBB- | Stable |
Rating Agency | Rating | Outlook |
Moody's | A3 | Stable |
S&P | BBB+ | Stable |
Fitch | A- | Stable |
2011 | 2010 | 2009 | ||||||||||
Property additions (1): | ||||||||||||
Utilities - | ||||||||||||
Electric Utilities | $ | 173,078 | (2) | $ | 232,466 | (2) | $ | 241,963 | (2) | |||
Gas Utilities | 43,954 | 51,363 | 43,005 | |||||||||
Non-regulated Energy - | ||||||||||||
Oil and Gas | 89,672 | 40,345 | 20,522 | |||||||||
Power Generation | 98,927 | (3) | 148,191 | (3) | 20,537 | (3) | ||||||
Coal Mining | 10,438 | 17,053 | 11,765 | |||||||||
Corporate | 13,279 | 7,182 | 9,807 | |||||||||
Capital expenditures for continuing operations | 429,348 | 496,600 | 347,599 | |||||||||
Discontinued operations investing activities | 2,359 | 390 | 220 | |||||||||
Total expenditures for property, plant and equipment | 431,707 | 496,990 | 347,819 | |||||||||
Common stock dividends | 59,202 | 56,467 | 55,151 | |||||||||
Maturities/redemptions of long-term debt | 8,382 | 59,926 | 2,173 | |||||||||
Discontinued operations financing activities | 158 | 2,037 | 2,047 | |||||||||
$ | 499,449 | $ | 615,420 | $ | 407,190 |
(1) | Includes accruals for property, plant and equipment. |
(2) | Includes (a) $13.1 million and $119.9 million for Wygen III construction in 2010 and 2009, respectively. During 2010 and 2009, we received reimbursement of $59.1 million and $58.0 million from the joint owners of the Wygen III facility. We own 52% of the Wygen III coal-fired plant that went into service on April 1, 2010; (b) $65.8 million, $116.3 million and $48.1 million in 2011, 2010 and 2009, respectively for construction of the 180 MW natural gas-fired generation facility at Colorado Electric, excluding transmission and (c) $23.1 million, $28.0 million and $21.1 million in new transmission projects in 2011, 2010 and 2009, respectively. |
(3) | Includes $98.2 million, $146.2 million and $16.4 million in 2011, 2010 and 2009, respectively, for construction of the 200 MW natural gas-fired power generation facility at Colorado IPP. |
2012 | 2013 | 2014 | |||||||||
Utilities: | |||||||||||
Electric Utilities(1) | $ | 247,000 | $ | 371,700 | $ | 206,300 | |||||
Gas Utilities | 46,000 | 54,700 | 43,800 | ||||||||
Non-regulated Energy: | |||||||||||
Oil and Gas | 112,200 | 123,500 | 126,100 | ||||||||
Power Generation | 2,850 | 4,900 | 6,700 | ||||||||
Coal Mining | 18,850 | 7,200 | 10,800 | ||||||||
Corporate | 10,300 | 18,700 | 12,100 | ||||||||
$ | 437,200 | $ | 580,700 | $ | 405,800 |
(1) | Capital expenditures for our Electric Utilities include expenditures associated with our Black Hills Power, Cheyenne Light and Colorado Electric energy resource plans. |
Payments Due by Period | |||||||||||||||
(in thousands) | |||||||||||||||
Contractual Obligations | Total | Less Than 1 Year | 1-3 Years | 4-5 Years | After 5 Years | ||||||||||
Long-term debt(a)(b) | $ | 1,283,038 | $ | 2,473 | $ | 591,446 | $ | 92,065 | $ | 597,054 | |||||
Unconditional purchase obligations(c) | 716,043 | 199,811 | 266,885 | 214,685 | 34,662 | ||||||||||
Operating lease obligations(d) | 14,498 | 2,799 | 6,686 | 2,660 | 2,353 | ||||||||||
Other long-term obligations(e) | 42,914 | — | — | — | 42,914 | ||||||||||
Employee benefit plans(f) | 126,860 | 13,230 | 58,640 | 26,940 | 28,050 | ||||||||||
Liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions(g) | 49,326 | — | 22,026 | 4,029 | 23,271 | ||||||||||
Notes payable | 345,000 | 345,000 | — | — | — | ||||||||||
Total contractual cash obligations(h) | $ | 2,577,679 | $ | 563,313 | $ | 945,683 | $ | 340,379 | $ | 728,304 |
(a) | Long-term debt amounts do not include discounts or premiums on debt. |
(b) | The following amounts are estimated for interest payments on long-term debt over the next five years: $79.2 million in 2012, $70.9 million in 2013, $51.2 million in 2014, $39.6 million in 2015 and $37.9 million in 2016. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2011. |
(c) | Unconditional purchase obligations include the energy and capacity costs associated with our power purchase agreements, the capacity and certain transmission, gas purchase and gas transportation and storage agreements. The energy charge under the PPA and the commodity price under the gas purchase contract are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2011 and price assumptions using existing prices at December 31, 2011. Our transmission obligations are based on filed tariffs as of December 31, 2011. A portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure are carried out for 60 days. |
(d) | Includes operating leases associated with several office buildings, warehouses and call centers, equipment and vehicles. |
(e) | Includes estimated asset retirement obligations associated with our Oil and Gas, Coal Mining, Electric Utilities and Gas Utilities segments as discussed in Note 10 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. |
(f) | Represents estimated employer contributions to employee benefit plans through the year 2021. |
(g) | Years 1-3 include an estimated reversal of approximately $10.2 million associated with the gain deferred from the tax treatment related to the IPP Transaction and the Aquila Transaction. The income tax refund receivable was reversed as a result of an agreement reached with the IRS in 2010. |
(h) | Amounts in the above table exclude: (1) any obligation that may arise from our derivatives, including interest rate swaps and commodity related contracts that have a negative fair value at December 31, 2011. These amounts have been excluded as it is impracticable to reasonably estimate the final amount and/or timing of any associated payments. (2) A portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to these fluctuations. The impact of these hedges is not included in the above table. (3) The obligations presented above do not include inter-company transactions. (4) The table above does not include obligations of our Energy Marketing segment. See Discontinued Operations discussion below. |
Outstanding at | Year | |||
Nature of Guarantee | December 31, 2011 | Expiring | ||
Guarantees for payment of obligations arising from commodity-related physical and financial transactions by Black Hills Utility Holdings | $ | 70,000 | Ongoing | |
Guarantees for payment obligations arising from purchase contracts for four gas turbines for Black Hills Colorado IPP | 384 | 2012 | ||
Guarantees for payment obligations arising from purchase contracts for two gas turbines for Colorado Electric | 56 | 2012 | ||
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric | 33,264 | 2012 | ||
Indemnification for subsidiary reclamation/surety bonds | 18,601 | Ongoing | ||
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Black Hills Utility Holdings | 10,000 | 2012 | ||
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply | 7,500 | 2012 | ||
$ | 139,805 |
2011 | 2010 | 2009 | |||||||
Cash provided by (used in) | |||||||||
Operating activities | $ | 223,704 | $ | 147,752 | $ | 270,502 | |||
Investing activities | $ | (447,007 | ) | $ | (389,168 | ) | $ | (269,823 | ) |
Financing activities | $ | 249,633 | $ | 160,953 | $ | (56,310 | ) |
• | Cash earnings (net income plus adjustments to reconcile income) were $31.2 million higher than prior year; |
• | An $11.1 million contribution in 2011 to our defined benefit plans compared to $30.0 million in 2010; |
• | Increased inflows from operating assets and liabilities of $20.1 million primarily as a result of: |
• | Increased cash outflows for materials, supplies and fuel primarily including purchases of natural gas at our Gas Utilities and purchases of additional supplies for generation built to support Colorado Electric customers; |
• | Increased cash inflows primarily due to adjustments to our PGA at our Gas Utilities in regulatory assets and regulatory liabilities combined with inflows from energy efficiency rebates; and |
• | Cash inflows from accounts receivable and other current assets primarily the result of a settlement reached with the IRS. |
• | Cash earnings (net income plus adjustments to reconcile income) increased $15.2 million; |
• | A $30.0 million contribution in 2010 to our defined benefit plans compared to $16.9 million in 2009; |
• | Outflows from operating assets and liabilities of $124.5 million as a result of: |
• | Materials, supplies and fuel used funds of $37.1 million primarily relating to decreases in the Gas Utilities gas storage in 2009 as compared to 2010; and |
• | Outflows of $23.9 million from higher use of funds in regulatory assets primarily related to energy efficiency rebates. |
• | Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric and Gas Utilities segments resulting from commodity price changes; and |
• | Interest rate risk associated with our variable rate credit facilities and our project financing floating rate debt as described in Notes 8 and 9 of our Notes to Consolidated Financial Statements. |
December 31, 2011 | December 31, 2010 | ||||||
Net derivative liabilities | $ | (16,676 | ) | $ | (7,188 | ) | |
Cash collateral | 19,416 | 10,355 | |||||
$ | 2,740 | $ | 3,167 |
Location | Transaction Date | Hedge Type | Term | Volume (MMBtu/day) | Price | |||||||
San Juan El Paso | 1/8/2010 | Swap | 01/12 - 03/12 | 2,500 | $ | 6.38 | ||||||
NWR | 1/8/2010 | Swap | 01/12 - 03/12 | 1,500 | $ | 6.47 | ||||||
AECO | 1/8/2010 | Swap | 01/12 - 03/12 | 500 | $ | 6.32 | ||||||
CIG | 1/8/2010 | Swap | 01/12 - 03/12 | 1,500 | $ | 6.43 | ||||||
San Juan El Paso | 1/25/2010 | Swap | 01/12 - 03/12 | 5,000 | $ | 6.44 | ||||||
San Juan El Paso | 10/31/2011 | Swap | 01/12 - 03/12 | 1,000 | $ | 3.71 | ||||||
San Juan El Paso | 3/19/2010 | Swap | 04/12 - 06/12 | 7,000 | $ | 5.27 | ||||||
CIG | 3/19/2010 | Swap | 04/12 - 06/12 | 1,500 | $ | 5.17 | ||||||
NWR | 3/19/2010 | Swap | 04/12 - 06/12 | 1,500 | $ | 5.20 | ||||||
AECO | 3/19/2010 | Swap | 04/12 - 06/12 | 250 | $ | 5.15 | ||||||
San Juan El Paso | 10/31/2011 | Swap | 04/12 - 06/12 | 1,000 | $ | 3.58 | ||||||
San Juan El Paso | 6/28/2010 | Swap | 07/12 - 09/12 | 3,500 | $ | 5.19 | ||||||
NWR | 6/28/2010 | Swap | 07/12 - 09/12 | 1,500 | $ | 5.01 | ||||||
CIG | 6/28/2010 | Swap | 07/12 - 09/12 | 1,500 | $ | 4.98 | ||||||
San Juan El Paso | 4/19/2011 | Swap | 07/12 - 09/12 | 2,000 | $ | 4.45 | ||||||
San Juan El Paso | 10/31/2011 | Swap | 07/12 - 09/12 | 1,000 | $ | 3.77 | ||||||
CIG | 2/18/2011 | Swap | 10/12 - 12/12 | 500 | $ | 4.42 | ||||||
San Juan El Paso | 2/18/2011 | Swap | 10/12 - 12/12 | 2,500 | $ | 4.46 | ||||||
NWR | 2/18/2011 | Swap | 10/12 - 12/12 | 1,000 | $ | 4.44 | ||||||
San Juan El Paso | 4/19/2011 | Swap | 10/12 - 12/12 | 2,000 | $ | 4.62 | ||||||
San Juan El Paso | 10/31/2011 | Swap | 10/12 - 12/12 | 1,000 | $ | 3.94 | ||||||
San Juan El Paso | 12/9/2011 | Swap | 10/12 - 12/12 | 1,000 | $ | 3.59 | ||||||
San Juan El Paso | 4/19/2011 | Swap | 01/13 - 03/13 | 2,500 | $ | 5.03 | ||||||
San Juan El Paso | 6/6/2011 | Swap | 01/13 - 03/13 | 2,500 | $ | 5.18 | ||||||
San Juan El Paso | 10/31/2011 | Swap | 01/13 - 03/13 | 1,000 | $ | 4.32 | ||||||
San Juan El Paso | 12/9/2011 | Swap | 01/13 - 03/13 | 1,000 | $ | 3.91 | ||||||
NWR | 12/9/2011 | Swap | 01/13 - 03/13 | 1,000 | $ | 4.02 | ||||||
San Juan El Paso | 4/19/2011 | Swap | 04/13 - 06/13 | 2,500 | $ | 4.64 | ||||||
San Juan El Paso | 10/31/2011 | Swap | 04/13 - 06/13 | 1,000 | $ | 4.13 | ||||||
San Juan El Paso | 12/9/2011 | Swap | 04/13 - 06/13 | 1,000 | $ | 3.77 | ||||||
NWR | 12/9/2011 | Swap | 04/13 - 06/13 | 1,000 | $ | 3.83 | ||||||
San Juan El Paso | 10/31/2011 | Swap | 07/13 - 09/13 | 1,000 | $ | 4.27 | ||||||
San Juan El Paso | 12/9/2011 | Swap | 07/13 - 09/13 | 1,000 | $ | 3.95 | ||||||
NWR | 12/9/2011 | Swap | 07/13 - 09/13 | 1,000 | $ | 3.97 | ||||||
San Juan El Paso | 12/9/2011 | Swap | 10/13 - 12/13 | 1,000 | $ | 4.05 | ||||||
NWR | 12/9/2011 | Swap | 10/13 - 12/13 | 1,000 | $ | 4.08 |
Location | Transaction Date | Hedge Type | Term | Volume (Bbls/month) | Price | |||||||
NYMEX | 1/8/2010 | Put | 01/12 - 03/12 | 5,000 | $ | 75.00 | ||||||
NYMEX | 1/25/2010 | Swap | 01/12 - 03/12 | 5,000 | $ | 83.30 | ||||||
NYMEX | 2/26/2010 | Swap | 01/12 - 03/12 | 5,000 | $ | 83.80 | ||||||
NYMEX | 3/19/2010 | Swap | 01/12 - 03/12 | 5,000 | $ | 83.80 | ||||||
NYMEX | 3/4/2011 | Swap | 01/12 - 12/12 | 2,000 | $ | 104.60 | ||||||
NYMEX | 3/19/2010 | Swap | 04/12 - 06/12 | 5,000 | $ | 84.00 | ||||||
NYMEX | 3/31/2010 | Put | 04/12 - 06/12 | 5,000 | $ | 75.00 | ||||||
NYMEX | 5/13/2010 | Swap | 04/12 - 06/12 | 5,000 | $ | 87.85 | ||||||
NYMEX | 8/17/2010 | Swap | 04/12 - 06/12 | 3,000 | $ | 82.60 | ||||||
NYMEX | 6/28/2010 | Swap | 07/12 - 09/12 | 5,000 | $ | 83.80 | ||||||
NYMEX | 8/17/2010 | Swap | 07/12 - 09/12 | 5,000 | $ | 82.85 | ||||||
NYMEX | 9/16/2010 | Swap | 07/12 - 09/12 | 5,000 | $ | 84.60 | ||||||
NYMEX | 4/20/2011 | Swap | 07/12 - 06/13 | 2,000 | $ | 106.80 | ||||||
NYMEX | 10/17/2011 | Put | 07/12 - 09/13 | 2,000 | $ | 80.00 | ||||||
NYMEX | 10/17/2011 | Call | 07/12 - 09/13 | 2,000 | $ | 95.00 | ||||||
NYMEX | 11/9/2010 | Swap | 10/12 - 12/12 | 5,000 | $ | 91.10 | ||||||
NYMEX | 1/6/2011 | Swap | 10/12 - 12/12 | 5,000 | $ | 93.40 | ||||||
NYMEX | 2/17/2011 | Swap | 10/12 - 03/13 | 5,000 | $ | 97.85 | ||||||
NYMEX | 1/20/2011 | Swap | 01/13 - 03/13 | 5,000 | $ | 94.20 | ||||||
NYMEX | 3/4/2011 | Swap | 01/13 - 03/13 | 3,000 | $ | 103.35 | ||||||
NYMEX | 11/2/2011 | Call | 01/13 - 12/13 | 3,000 | $ | 100.00 | ||||||
NYMEX | 11/2/2011 | Put | 01/13 - 12/13 | 3,000 | $ | 77.50 | ||||||
NYMEX | 6/3/2011 | Swap | 04/13 - 06/13 | 5,000 | $ | 100.90 | ||||||
NYMEX | 7/27/2011 | Swap | 04/13 - 06/13 | 5,000 | $ | 102.72 | ||||||
NYMEX | 12/9/2011 | Call | 04/13 - 06/13 | 2,000 | $ | 100.50 | ||||||
NYMEX | 12/9/2011 | Put | 04/13 - 06/13 | 2,000 | $ | 90.00 | ||||||
NYMEX | 7/27/2011 | Swap | 07/13 - 12/13 | 5,000 | $ | 102.75 | ||||||
NYMEX | 10/17/2011 | Swap | 07/13 - 09/13 | 2,000 | $ | 88.50 | ||||||
NYMEX | 12/9/2011 | Call | 07/13 - 09/13 | 3,000 | $ | 99.00 | ||||||
NYMEX | 12/9/2011 | Put | 07/13 - 09/13 | 3,000 | $ | 90.00 | ||||||
NYMEX | 12/9/2011 | Call | 10/13 - 12/13 | 4,000 | $ | 98.00 | ||||||
NYMEX | 12/9/2011 | Put | 10/13 - 12/13 | 4,000 | $ | 90.00 |
Notional | Weighted Average Fixed Interest Rate | Maximum Terms in Years | Current Assets | Non- current Assets | Current Liabilities | Non- current Liabilities | Pre-tax Accumulated Other Comprehensive Income (Loss) | Pre-tax Income (Loss) | |||||||||||||||||||||||||
December 31, 2011 | |||||||||||||||||||||||||||||||||
Interest rate swaps | $ | 150,000 | 5.04 | % | 5.0 | $ | — | $ | — | $ | 6,513 | $ | 20,363 | $ | (26,876 | ) | $ | — | |||||||||||||||
Interest rate swaps - De-designated | 250,000 | 5.67 | % | 2.0 | — | — | 75,295 | 20,696 | — | (42,010 | ) | ||||||||||||||||||||||
$ | 400,000 | $ | — | $ | — | $ | 81,808 | $ | 41,059 | $ | (26,876 | ) | $ | (42,010 | ) | ||||||||||||||||||
December 31, 2010 | |||||||||||||||||||||||||||||||||
Interest rate swaps | $ | 150,000 | 5.04 | % | 6.0 | $ | — | $ | — | $ | 6,823 | $ | 14,976 | $ | (21,799 | ) | $ | — | |||||||||||||||
Interest rate swaps - De-designated | 250,000 | 5.67 | % | 1.0 | — | — | 53,980 | — | — | (15,193 | ) | ||||||||||||||||||||||
$ | 400,000 | $ | — | $ | — | $ | 60,803 | $ | 14,976 | $ | (21,799 | ) | $ | (15,193 | ) |
2012 | 2013 | 2014 | 2015 | 2016 | Thereafter | Total | |||||||||||||||
Long-term debt | |||||||||||||||||||||
Fixed rate(a) | $ | 73 | $ | 225,000 | $ | 256,450 | $ | — | $ | — | $ | 577,200 | $ | 1,058,723 | |||||||
Average interest rate (b) | 13.66 | % | 6.5 | % | 8.89 | % | — | % | — | % | 6.27 | % | 6.95 | % | |||||||
Variable rate | $ | 2,400 | $ | 103,973 | $ | 6,023 | $ | 6,964 | $ | 85,101 | $ | 19,854 | $ | 224,315 | |||||||
Average interest rate (b) | 3.66 | % | 1.76 | % | 3.66 | % | 3.66 | % | 3.66 | % | 0.55 | % | 2.51 | % | |||||||
Total long-term debt | $ | 2,473 | $ | 328,973 | $ | 262,473 | $ | 6,964 | $ | 85,101 | $ | 597,054 | $ | 1,283,038 | |||||||
Average interest rate (b) | 3.95 | % | 5 | % | 8.77 | % | 3.66 | % | 3.66 | % | 6.08 | % | 6.18 | % |
(a) | Excludes unamortized premium or discount. |
(b) | The average interest rates do not include the effect of interest rate swaps. |
Total fair value of energy marketing positions marked-to-market at December 31, 2010 | $ | 23,418 | (a) | |
Net cash settled during the period on positions that existed at December 31, 2009 | (3,376 | ) | ||
Change in fair value due to change in assumptions | — | |||
Unrealized gain (loss) on new positions entered during the period and still existing at December 31, 2011 | 34,577 | |||
Realized (gain) losses on positions that existed at December 31, 2010 and were settled during the period | (12,941 | ) | ||
Change in cash collateral | 4,086 | |||
Unrealized gain (loss) on positions that existed at December 31, 2010 and still existed at December 31, 2011 | (23,548 | ) | ||
Total fair value of energy marketing positions at December 31, 2011 | $ | 22,216 | (a) |
(a) | The fair value of energy marketing positions consists of the mark-to-market values of derivative assets/liabilities and market value adjustments to natural gas inventory that has been designated as a hedged item as part of a fair value hedge, as follows (in thousands): |
December 31, 2011 | December 31, 2010 | |||||
Net derivative assets | $ | 18,731 | $ | 28,524 | ||
Cash collateral | 8,044 | 3,958 | ||||
Market adjustment recorded in material, supplies and fuel | (4,558 | ) | (9,064 | ) | ||
Total fair value of energy marketing positions marked-to-market | $ | 22,217 | $ | 23,418 |
Maturities | ||||||||||||
Source of Fair Value | Less than 1 year | 1 - 2 years | Total Fair Value | |||||||||
Level 1 | $ | — | $ | — | $ | — | ||||||
Level 2 | 5,371 | 12,631 | 18,002 | |||||||||
Level 3 | (2,806 | ) | 3,535 | 729 | ||||||||
Cash collateral | 8,044 | — | 8,044 | |||||||||
Market value adjustment for inventory (see footnote (a) above) | — | — | — | |||||||||
Total fair value of our energy marketing positions | $ | 10,609 | $ | 16,166 | $ | 26,775 |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Report of Independent Registered Public Accounting Firm | |
Consolidated Statements of Income for the three years ended December 31, 2011 | |
Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 2011 | |
Consolidated Balance Sheets as of December 31, 2011 and 2010 | |
Consolidated Statements of Cash Flows for the three years ended December 31, 2011 | |
Consolidated Statements of Common Stockholders' Equity for the three years ended December 31, 2011 | |
Notes to Consolidated Financial Statements |
Years ended | December 31, 2011 | December 31, 2010 | December 31, 2009 | ||||||
(in thousands, except per share amounts) | |||||||||
Revenue: | |||||||||
Utilities | $ | 1,155,519 | $ | 1,109,761 | $ | 1,091,638 | |||
Non-regulated energy | 116,669 | 109,930 | 107,074 | ||||||
Total revenue | 1,272,188 | 1,219,691 | 1,198,712 | ||||||
Operating expenses: | |||||||||
Utilities - | |||||||||
Fuel, purchased power and cost of gas sold | 574,989 | 566,967 | 595,240 | ||||||
Operations and maintenance | 247,496 | 251,375 | 241,995 | ||||||
Non-regulated energy operations and maintenance | 93,453 | 71,672 | 76,137 | ||||||
Gain on sale of operating assets | — | (8,921 | ) | (25,971 | ) | ||||
Depreciation, depletion and amortization | 135,591 | 126,606 | 120,938 | ||||||
Impairment of long-lived assets | — | — | 43,301 | ||||||
Taxes - property, production and severance | 33,710 | 27,592 | 21,687 | ||||||
Other operating expenses | 710 | 980 | 1,230 | ||||||
Total operating expenses | 1,085,949 | 1,036,271 | 1,074,557 | ||||||
Operating income | 186,239 | 183,420 | 124,155 | ||||||
Other income (expense): | |||||||||
Interest charges - | |||||||||
Interest expense (including amortization of debt issuance costs, premiums and discounts, realized amount on interest rate swaps) | (116,684 | ) | (105,676 | ) | (89,441 | ) | |||
Allowance for funds used during construction - borrowed | 14,041 | 10,689 | 5,839 | ||||||
Capitalized interest | 11,260 | 4,381 | 349 | ||||||
Unrealized (loss) gain on interest rate swaps, net | (42,010 | ) | (15,193 | ) | 55,653 | ||||
Interest income | 2,017 | 541 | 923 | ||||||
Allowance for funds used during construction - equity | 932 | 2,996 | 5,891 | ||||||
Other expense | (817 | ) | (140 | ) | (513 | ) | |||
Other income | 2,490 | 2,733 | 5,921 | ||||||
Total other income (expense) | (128,771 | ) | (99,669 | ) | (15,378 | ) | |||
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes | 57,468 | 83,751 | 108,777 | ||||||
Equity in earnings (loss) of unconsolidated subsidiaries | 1,121 | 1,559 | 1,343 | ||||||
Income tax (expense) benefit | (18,224 | ) | (22,169 | ) | (32,851 | ) | |||
Income (loss) from continuing operations | 40,365 | 63,141 | 77,269 | ||||||
Income (loss) from discontinued operations, net of tax | 9,365 | 5,544 | 4,286 | ||||||
Net income available for common stock | $ | 49,730 | $ | 68,685 | $ | 81,555 | |||
Income (loss) per share, Basic - | |||||||||
Income (loss) from continuing operations, per share | $ | 1.01 | $ | 1.62 | $ | 2.00 | |||
Income (loss) from discontinued operations, per share | 0.24 | 0.14 | 0.11 | ||||||
Total income (loss) per share, Basic | $ | 1.25 | $ | 1.76 | $ | 2.11 | |||
Income (loss) per share, Diluted - | |||||||||
Income (loss) from continuing operations, per share | $ | 1.01 | $ | 1.62 | $ | 2.00 | |||
Income (loss) from discontinued operations, per share | 0.23 | 0.14 | 0.11 | ||||||
Total income (loss) per share, Diluted | $ | 1.24 | $ | 1.76 | $ | 2.11 | |||
Weighted average common shares outstanding: | |||||||||
Basic | 39,864 | 38,916 | 38,614 | ||||||
Diluted | 40,081 | 39,091 | 38,684 |
Years ended | December 31, 2011 | December 31, 2010 | December 31, 2009 | ||||||
(in thousands) | |||||||||
Net income available for common stock | $ | 49,730 | $ | 68,685 | $ | 81,555 | |||
Other comprehensive income (loss), net of tax: | |||||||||
Benefit plan liability adjustments | (7,934 | ) | (1,521 | ) | 4,491 | ||||
Fair value adjustment on derivatives designated as cash flow hedges | (2,831 | ) | 1,336 | (17,481 | ) | ||||
Reclassification adjustment of cash flow hedges settled and included in net income (loss) | 1,468 | (4,232 | ) | 12,609 | |||||
Reclassification adjustment of cash flow hedges settled and included in regulatory assets or liabilities | — | — | — | ||||||
Other comprehensive income (loss), net of tax | (9,297 | ) | (4,417 | ) | (381 | ) | |||
Comprehensive income (loss) | $ | 40,433 | $ | 64,268 | $ | 81,174 |
As of | ||||||
December 31, 2011 | December 31, 2010 | |||||
(in thousands) | ||||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 21,628 | $ | 16,437 | ||
Restricted cash | 9,254 | 4,260 | ||||
Accounts receivable, net | 156,774 | 171,816 | ||||
Materials, supplies and fuel | 84,064 | 62,915 | ||||
Derivative assets, current | 18,583 | 12,710 | ||||
Income tax receivable, net | 9,344 | — | ||||
Deferred income tax assets, net, current | 37,202 | 20,664 | ||||
Regulatory assets, current | 59,955 | 66,429 | ||||
Other current assets | 21,266 | 14,695 | ||||
Assets of discontinued operations | 340,851 | 314,235 | ||||
Total current assets | 758,921 | 684,161 | ||||
Investments | 17,261 | 17,780 | ||||
Property, plant and equipment | 3,724,016 | 3,353,509 | ||||
Less accumulated depreciation and depletion | (934,441 | ) | (861,775 | ) | ||
Total property, plant and equipment, net | 2,789,575 | 2,491,734 | ||||
Other assets: | ||||||
Goodwill | 353,396 | 353,396 | ||||
Intangible assets, net | 3,843 | 4,069 | ||||
Derivative assets, non-current | 1,971 | 2,625 | ||||
Regulatory assets, non-current | 182,175 | 138,405 | ||||
Other assets, non-current | 19,941 | 19,339 | ||||
Total other assets | 561,326 | 517,834 | ||||
TOTAL ASSETS | $ | 4,127,083 | $ | 3,711,509 |
As of | ||||||
December 31, 2011 | December 31, 2010 | |||||
(in thousands, except share amounts) | ||||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 104,748 | $ | 146,556 | ||
Accrued liabilities | 151,319 | 147,643 | ||||
Derivative liabilities, current | 84,367 | 64,617 | ||||
Accrued income tax, net | — | 3,348 | ||||
Regulatory liabilities, current | 16,231 | 3,943 | ||||
Notes payable | 345,000 | 249,000 | ||||
Current maturities of long-term debt | 2,473 | 5,181 | ||||
Liabilities of discontinued operations | 173,929 | 173,323 | ||||
Total current liabilities | 878,067 | 793,611 | ||||
Long-term debt, net of current maturities | 1,280,409 | 1,186,050 | ||||
Deferred credits and other liabilities: | ||||||
Deferred income tax liabilities, net, non-current | 300,988 | 275,842 | ||||
Derivative liabilities, non-current | 49,033 | 17,897 | ||||
Regulatory liabilities, non-current | 108,217 | 84,611 | ||||
Benefit plan liabilities | 177,480 | 124,709 | ||||
Other deferred credits and other liabilities | 123,553 | 128,519 | ||||
Total deferred credits and other liabilities | 759,271 | 631,578 | ||||
Commitments and contingencies (See Notes 3, 8, 9, 10, 13, 18, 19 and 20) | ||||||
Stockholders' equity: | ||||||
Common stock equity- | ||||||
Common stock $1 par value; 100,000,000 shares authorized; issued: 43,957,502 shares at 2011 and 39,280,048 shares at 2010, respectively | 43,958 | 39,280 | ||||
Additional paid-in capital | 722,623 | 598,805 | ||||
Retained earnings | 476,603 | 486,075 | ||||
Treasury stock at cost - 32,766 shares at 2011 and 10,962 shares at 2010, respectively | (970 | ) | (309 | ) | ||
Accumulated other comprehensive income (loss) | (32,878 | ) | (23,581 | ) | ||
Total stockholders' equity | 1,209,336 | 1,100,270 | ||||
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 4,127,083 | $ | 3,711,509 |
Year ended | December 31, 2011 | December 31, 2010 | December 31, 2009 | ||||||
(in thousands) | |||||||||
Operating activities: | |||||||||
Net income | $ | 49,730 | $ | 68,685 | $ | 81,555 | |||
(Income) loss from discontinued operations, net of tax | (9,365 | ) | (5,544 | ) | (4,286 | ) | |||
Income (loss) from continuing operations | 40,365 | 63,141 | 77,269 | ||||||
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities - | |||||||||
Depreciation, depletion and amortization | 135,591 | 126,606 | 120,938 | ||||||
Impairment of long-lived assets | — | — | 43,301 | ||||||
Gain on sale of operating assets | — | (8,921 | ) | (25,971 | ) | ||||
Stock compensation | 5,643 | 5,637 | 3,908 | ||||||
Unrealized mark-to-market loss (gain) on interest rate swaps | 42,010 | 15,193 | (55,653 | ) | |||||
Equity in (earnings) loss of unconsolidated subsidiaries | (1,121 | ) | (1,559 | ) | (1,343 | ) | |||
Allowance for funds used during construction - equity | (932 | ) | (2,996 | ) | (5,891 | ) | |||
Derivative fair value adjustments | (8,693 | ) | 13,546 | 19,083 | |||||
Deferred income taxes | 33,600 | 17,354 | 45,610 | ||||||
Employee benefit plans | 14,586 | 16,342 | 16,349 | ||||||
Other adjustments | 10,602 | (3,851 | ) | 4,539 | |||||
Change in certain operating assets and liabilities- | |||||||||
Materials, supplies and fuel | (21,385 | ) | (338 | ) | 36,767 | ||||
Accounts receivable and other current assets | (4,202 | ) | (18,480 | ) | 26,593 | ||||
Accounts payable and other current liabilities | (31,091 | ) | (12,848 | ) | 4,404 | ||||
Regulatory assets | 12,691 | (21,283 | ) | 2,598 | |||||
Regulatory liabilities | 11,198 | 50 | 1,265 | ||||||
Contributions to defined pension plans | (11,050 | ) | (30,015 | ) | (16,945 | ) | |||
Other operating activities | (11,118 | ) | (1,013 | ) | 7,091 | ||||
Net cash provided by operating activities of continuing operations | 216,694 | 156,565 | 303,912 | ||||||
Net cash provided by (used in) operating activities of discontinued operations | 7,010 | (8,813 | ) | (33,410 | ) | ||||
Net cash provided by operating activities | 223,704 | 147,752 | 270,502 | ||||||
Investing activities: | |||||||||
Property, plant and equipment additions | (440,698 | ) | (472,292 | ) | (346,650 | ) | |||
Payment for acquisition of net assets, net of cash acquired | — | (2,250 | ) | — | |||||
Proceeds from sale of operating assets | 583 | 70,357 | 84,661 | ||||||
Working capital adjustment - Aquila Transaction | — | — | 7,880 | ||||||
Other investing activities | (4,533 | ) | 15,407 | (15,494 | ) | ||||
Net cash provided by (used in) investing activities of continuing operations | (444,648 | ) | (388,778 | ) | (269,603 | ) | |||
Net cash provided by (used in) investing activities of discontinued operations | (2,359 | ) | (390 | ) | (220 | ) | |||
Net cash provided by (used in) investing activities | (447,007 | ) | (389,168 | ) | (269,823 | ) | |||
Financing activities: | |||||||||
Dividends paid on common stock | (59,202 | ) | (56,467 | ) | (55,151 | ) | |||
Common stock issued | 123,041 | 3,246 | 4,819 | ||||||
Short-term borrowings - repayments | (821,300 | ) | (770,000 | ) | (1,125,300 | ) | |||
Short-term borrowings - issuances | 1,017,300 | 854,500 | 586,000 | ||||||
Long-term debt - issuance | — | 200,000 | 543,069 | ||||||
Long-term debt - repayments | (8,382 | ) | (59,926 | ) | (2,173 | ) | |||
Other financing activities | (1,666 | ) | (8,363 | ) | (5,527 | ) | |||
Net cash provided by (used in) financing activities of continuing operations | 249,791 | 162,990 | (54,263 | ) | |||||
Net cash provided by (used in) financing activities of discontinued operations | (158 | ) | (2,037 | ) | (2,047 | ) | |||
Net cash provided by (used in) financing activities | 249,633 | 160,953 | (56,310 | ) | |||||
Net change in cash and cash equivalents | 26,330 | (80,463 | ) | (55,631 | ) | ||||
Cash and cash equivalents beginning of year * | 32,438 | 112,901 | 168,532 | ||||||
Cash and cash equivalents end of year * | $ | 58,768 | $ | 32,438 | $ | 112,901 |
* | Cash and cash equivalents include cash of discontinued operations of $37.1 million, $16.0 million, $97.5 million and $94.7 million at December 31, 2011, 2010, 2009 and 2008, respectively. |
(in thousands except share and per share amounts) | Common Stock | Treasury Stock | ||||||||||||||||||||
Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Total | |||||||||||||||
Balance at December 31, 2008 | 38,676,054 | $ | 38,676 | 40,183 | $ | (1,392 | ) | $ | 584,582 | $ | 447,453 | $ | (18,783 | ) | $ | 1,050,536 | ||||||
Net income (loss) available for common stock | — | — | — | — | — | 81,555 | — | 81,555 | ||||||||||||||
Other comprehensive income (loss), net of tax | — | — | — | — | — | — | (381 | ) | (381 | ) | ||||||||||||
Dividends on common stock | — | — | — | — | — | (55,151 | ) | — | (55,151 | ) | ||||||||||||
Share-based compensation | 158,140 | 159 | (31,349 | ) | 1,168 | 4,830 | — | — | 6,157 | |||||||||||||
Tax effect of share-based compensation | — | — | — | — | (120 | ) | — | — | (120 | ) | ||||||||||||
Dividend reinvestment and stock purchase plan | 143,332 | 143 | — | — | 2,098 | — | — | 2,241 | ||||||||||||||
Balance at December 31, 2009 | 38,977,526 | $ | 38,978 | 8,834 | $ | (224 | ) | $ | 591,390 | $ | 473,857 | $ | (19,164 | ) | $ | 1,084,837 | ||||||
Net income (loss) available for common stock | — | — | — | — | — | 68,685 | — | 68,685 | ||||||||||||||
Other comprehensive income (loss), net of tax | — | — | — | — | — | — | (4,417 | ) | (4,417 | ) | ||||||||||||
Dividends on common stock | — | — | — | — | — | (56,467 | ) | — | (56,467 | ) | ||||||||||||
Share-based compensation | 195,915 | 196 | 2,128 | (85 | ) | 4,706 | — | — | 4,817 | |||||||||||||
Tax effect of share-based compensation | — | — | — | — | (33 | ) | — | — | (33 | ) | ||||||||||||
Equity forward | — | — | — | — | (288 | ) | — | — | (288 | ) | ||||||||||||
Dividend reinvestment and stock purchase plan | 106,231 | 106 | — | — | 3,035 | — | — | 3,141 | ||||||||||||||
Other stock transactions | 376 | — | — | — | (5 | ) | — | — | (5 | ) | ||||||||||||
Balance at December 31, 2010 | 39,280,048 | $ | 39,280 | 10,962 | $ | (309 | ) | $ | 598,805 | $ | 486,075 | $ | (23,581 | ) | $ | 1,100,270 | ||||||
Net income (loss) available for common stock | — | — | — | — | — | 49,730 | — | 49,730 | ||||||||||||||
Other comprehensive income (loss), net of tax | — | — | — | — | — | — | (9,297 | ) | (9,297 | ) | ||||||||||||
Dividends on common stock | — | — | — | — | — | (59,202 | ) | — | (59,202 | ) | ||||||||||||
Share-based compensation | 161,424 | 161 | 21,804 | (661 | ) | 5,576 | — | — | 5,076 | |||||||||||||
Tax effect of share-based compensation | — | — | — | — | (28 | ) | — | — | (28 | ) | ||||||||||||
Issuance of common stock | 4,413,519 | 4,414 | — | — | 115,216 | — | — | 119,630 | ||||||||||||||
Dividend reinvestment and stock purchase plan | 102,511 | 103 | — | — | 3,099 | — | — | 3,202 | ||||||||||||||
Other stock transactions | — | — | — | — | (45 | ) | — | — | (45 | ) | ||||||||||||
Balance at December 31, 2011 | 43,957,502 | $ | 43,958 | 32,766 | $ | (970 | ) | $ | 722,623 | $ | 476,603 | $ | (32,878 | ) | $ | 1,209,336 |
(1) | BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES |
2011 | Accounts Receivable, Trade | Unbilled Revenues | Less Allowance for Doubtful Accounts | Accounts Receivable, net | ||||||||
Electric | $ | 42,773 | $ | 21,151 | $ | (545 | ) | $ | 63,379 | |||
Gas | 39,353 | 38,992 | (1,011 | ) | 77,334 | |||||||
Oil and Gas | 11,282 | — | (105 | ) | 11,177 | |||||||
Coal Mining | 4,056 | — | — | 4,056 | ||||||||
Power Generation | 282 | — | — | 282 | ||||||||
Corporate | 546 | — | — | 546 | ||||||||
Total | $ | 98,292 | $ | 60,143 | $ | (1,661 | ) | $ | 156,774 |
2010 | Accounts Receivable, Trade | Unbilled Revenues | Less Allowance for Doubtful Accounts | Accounts Receivable, net | ||||||||
Electric | $ | 51,005 | $ | 19,572 | $ | (708 | ) | $ | 69,869 | |||
Gas | 41,970 | 40,376 | (1,425 | ) | 80,921 | |||||||
Oil and Gas | 6,213 | — | (161 | ) | 6,052 | |||||||
Coal Mining | 2,420 | — | — | 2,420 | ||||||||
Power Generation | 307 | — | — | 307 | ||||||||
Corporate | 12,247 | — | — | 12,247 | ||||||||
Total | $ | 114,162 | $ | 59,948 | $ | (2,294 | ) | $ | 171,816 |
December 31, 2011 | December 31, 2010 | |||||
Materials and supplies | $ | 40,838 | $ | 31,537 | ||
Fuel - Electric Utilities | 8,201 | 9,687 | ||||
Natural gas in storage - Gas Utilities | 35,025 | 21,691 | ||||
Total Materials, supplies and fuel | $ | 84,064 | $ | 62,915 |
Electric Utilities | Gas Utilities | Power Generation | Total | |||||||||
Ending balance at December 31, 2009 | $ | 249,620 | $ | 93,914 | $ | 8,765 | $ | 352,299 | ||||
Additions (adjustments) | 867 | 230 | — | 1,097 | ||||||||
Ending balance at December 31, 2010 | $ | 250,487 | $ | 94,144 | $ | 8,765 | $ | 353,396 | ||||
Additions (adjustments) | — | — | — | — | ||||||||
Ending balance at December 31, 2011 | $ | 250,487 | $ | 94,144 | $ | 8,765 | $ | 353,396 |
2011 | 2010 | 2009 | |||||||
Intangible assets, net, beginning balance | $ | 4,069 | $ | 4,309 | $ | 4,884 | |||
Additions (adjustments) | — | — | (365 | ) | |||||
Amortization expense | (226 | ) | (240 | ) | (210 | ) | |||
Intangible assets, net, ending balance | $ | 3,843 | $ | 4,069 | $ | 4,309 |
* | Amortization expense for existing intangible assets is expected to be $0.2 million, $0.2 million, $0.2 million, $0.2 million, and $0.2 million for 2012, 2013, 2014, 2015, and 2016, respectively. |
• | Commodity derivatives - Oil and Gas: Our derivative option contracts are valued under the income approach using option pricing models based on data either readily observable in public markets, derived from public markets or provided by counterparties who regularly trade in public markets. Our derivative swap contracts are valued under the income approach using a discounted cash flow model based on data either readily observable or derived from public markets. |
• | Commodity derivatives - Utilities: Our gas hedge portfolio for our Utilities generally consists of futures, basis swaps and option contracts. The fair value of these financial instruments is estimated based on market trading information, where available. Absent published market values for an instrument or other asset, management uses observable market data to arrive at its estimates of fair value. These contracts have been classified as Level 2 measurements. |
• | Interest rate swaps: The fair value of our interest rate swap contracts are determined using standard valuation models. The significant inputs used in these models are readily available in public markets or can be derived from observable market transactions and; therefore, these derivative contracts have been classified as Level 2. Inputs used in these standard valuation models include the applicable market forward rates and discount rates. |
Maximum Recovery or | As of | As of | |||||
Settlement Period (in years) | December 31, 2011 | December 31, 2010 | |||||
Regulatory assets | |||||||
Deferred energy and fuel costs adjustments - current | 1 | $ | 33,526 | $ | 30,298 | ||
Deferred gas cost adjustments and gas price derivatives | 1 | 26,208 | 39,407 | ||||
AFUDC | 45 | 12,482 | 13,391 | ||||
Employee benefit plans | 13 | 120,708 | 83,144 | ||||
Environmental | subject to approval | 1,770 | 2,353 | ||||
Asset retirement obligations | 44 | 3,097 | 3,066 | ||||
Bond issue cost | 25 | 3,704 | 3,847 | ||||
Renewable energy standard adjustment | 5 | 20,095 | 14,254 | ||||
Flow through accounting | 35 | 12,191 | 7,491 | ||||
Other regulatory assets | various | 8,349 | 7,583 | ||||
$ | 242,130 | $ | 204,834 | ||||
Regulatory liabilities | |||||||
Deferred energy and gas costs | 1 | $ | 16,961 | $ | 1,200 | ||
Employee benefit plans | 13 | 59,455 | 36,155 | ||||
Cost of removal | 44 | 42,257 | 39,638 | ||||
Revenue subject to refund | 1 | 443 | 1,016 | ||||
Other regulatory liabilities | various | 5,332 | 10,545 | ||||
$ | 124,448 | $ | 88,554 |
December 31, 2011 | December 31, 2010 | December 31, 2009 | |||||||
Income (loss) from continuing operations | $ | 40,365 | $ | 63,141 | $ | 77,269 | |||
Weighted average shares - basic * | 39,864 | 38,916 | 38,614 | ||||||
Dilutive effect of: | |||||||||
Stock options | 19 | 14 | — | ||||||
Restricted stock | 153 | 107 | 66 | ||||||
Equity forward instrument | — | 29 | — | ||||||
Other dilutive effects | 45 | 25 | 4 | ||||||
Weighted average shares - diluted | 40,081 | 39,091 | 38,684 |
* | On November 1, 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information. |
December 31, 2011 | December 31, 2010 | December 31, 2009 | ||||
Options to purchase common stock | 105 | 158 | 462 | |||
Restricted stock | 17 | 1 | 3 | |||
Other | 19 | 1 | 45 | |||
141 | 160 | 510 |
• | Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric and Gas Utilities segments resulting from commodity price changes; and |
• | Interest rate risk associated with variable rate credit facilities and project financing floating rate debt and our derivative instruments as described in Notes 4, 5, 8 and 9. |
December 31, 2011 | December 31, 2010 | |||||||||||
Crude oil swaps/options | Natural gas swaps | Crude oil swaps/options | Natural gas swaps | |||||||||
Notional (a) | 528,000 | 5,406,250 | 424,500 | 6,821,800 | ||||||||
Maximum duration in years (b) | 1.25 | 1.75 | 0.25 | 0.25 | ||||||||
Derivative assets, current | $ | 729 | $ | 8,010 | $ | 248 | $ | 7,675 | ||||
Derivative assets, non-current | $ | 771 | $ | 1,148 | $ | 19 | $ | 2,606 | ||||
Derivative liabilities, current | $ | 2,559 | $ | — | $ | 3,814 | $ | — | ||||
Derivative liabilities, non-current | $ | 811 | $ | 7 | $ | 1,301 | $ | — | ||||
Pre-tax accumulated other comprehensive income (loss) | $ | (1,928 | ) | $ | 9,152 | $ | (5,313 | ) | $ | 10,281 | ||
Revenue (c) | $ | 58 | $ | — | $ | 465 | $ | — |
(a) | Crude in Bbls, gas in MMBtu. |
(b) | Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument. |
(c) | Represents the amortization of put premiums. |
December 31, 2011 | December 31, 2010 | |||||||
Natural gas (notional amounts in MMBtu) | Notional | Latest Expiration (months) | Notional | Latest Expiration (months) | ||||
Natural gas futures purchased | 14,310,000 | 84 | 6,670,000 | 15 | ||||
Natural gas options purchased | 1,720,000 | 3 | 1,730,000 | 3 | ||||
Natural gas basis swaps purchased | 7,160,000 | 60 | — | — |
December 31, 2011 | December 31, 2010 | |||||
Derivative assets, current | $ | 9,844 | $ | 4,787 | ||
Derivative assets, non-current | $ | 52 | $ | — | ||
Derivative liabilities, current | $ | — | $ | — | ||
Derivative liabilities, non-current | $ | 7,156 | $ | 1,620 | ||
Net unrealized gain (loss) included in Regulatory assets or Regulatory liabilities | $ | 17,556 | $ | 8,030 | ||
Cash collateral receivable (payable) included in derivative assets/liabilities | $ | 19,416 | $ | 10,355 | ||
Option premium included in Derivative assets, current | $ | 880 | $ | 842 |
December 31, 2011 | December 31, 2010 | |||||||||||
Interest Rate Swaps | De-designated Interest Rate Swaps (a) | Interest Rate Swaps | De-designated Interest Rate Swaps (a) | |||||||||
Notional | $ | 150,000 | $ | 250,000 | $ | 150,000 | $ | 250,000 | ||||
Weighted average fixed interest rate | 5.04 | % | 5.67 | % | 5.04 | % | 5.67 | % | ||||
Maximum terms in years | 5.0 | 2.0 | 6.0 | 1.0 | ||||||||
Derivative assets, current | $ | — | $ | — | $ | — | $ | — | ||||
Derivative assets, non-current | $ | — | $ | — | $ | — | $ | — | ||||
Derivative liabilities, current | $ | 6,513 | $ | 75,295 | $ | 6,823 | $ | 53,980 | ||||
Derivative liabilities, non-current | $ | 20,363 | $ | 20,696 | $ | 14,976 | $ | — | ||||
Pre-tax accumulated other comprehensive income (loss) | $ | (26,876 | ) | $ | — | $ | (21,799 | ) | $ | — | ||
Pre-tax gain (loss) included in Consolidated Statements of Income | $ | — | $ | (42,010 | ) | $ | — | $ | (15,193 | ) | ||
Cash collateral receivable (payable) included in Consolidated Balance Sheets | $ | — | $ | — | $ | — | $ | — |
(a) | The maximum term in years reflects the amended mandatory early termination dates. If the mandatory early termination dates are not extended, the swaps will require cash settlement based on the swap value of the termination date. When extended, de-designated swaps totaling $100.0 million terminate in 7 years and de-designated swaps totaling $150.0 million terminate in 17 years. |
As of December 31, 2011 | ||||||||||||||||||
Level 1 | Level 2 | Level 3 | Counterparty Netting | Cash Collateral | Total | |||||||||||||
Assets: | ||||||||||||||||||
Commodity derivatives - Oil and Gas | $ | — | $ | 9,885 | $ | 768 | $ | 5 | $ | — | $ | 10,658 | ||||||
Commodity derivatives - Utilities | — | (9,520 | ) | — | — | 19,416 | 9,896 | |||||||||||
Money market fund | 6,005 | — | — | — | — | 6,005 | ||||||||||||
Total | $ | 6,005 | $ | 365 | $ | 768 | $ | 5 | $ | 19,416 | $ | 26,559 | ||||||
Liabilities: | ||||||||||||||||||
Commodity derivatives - Oil and Gas | $ | — | $ | 2,207 | $ | 1,165 | $ | 5 | $ | — | $ | 3,377 | ||||||
Commodity derivatives - Utilities | — | 7,156 | — | — | — | 7,156 | ||||||||||||
Interest rate swaps | — | 122,867 | — | — | — | 122,867 | ||||||||||||
Total | $ | — | $ | 132,230 | $ | 1,165 | $ | 5 | $ | — | $ | 133,400 |
As of December 31, 2010 | ||||||||||||||||||
Level 1 | Level 2 | Level 3 | Counterparty Netting | Cash Collateral | Total | |||||||||||||
Assets: | ||||||||||||||||||
Commodity derivatives - Oil and Gas | $ | — | $ | 10,281 | $ | 266 | $ | — | $ | — | $ | 10,547 | ||||||
Commodity derivatives - Utilities | — | (5,568 | ) | — | — | 10,355 | 4,787 | |||||||||||
Money market fund | 8,050 | — | — | — | — | 8,050 | ||||||||||||
Total | $ | 8,050 | $ | 4,713 | $ | 266 | $ | — | $ | 10,355 | $ | 23,384 | ||||||
Liabilities: | ||||||||||||||||||
Commodity derivatives - Oil and Gas | $ | — | $ | 5,115 | $ | — | $ | — | $ | — | $ | 5,115 | ||||||
Commodity derivatives - Utilities | — | 1,620 | — | — | — | 1,620 | ||||||||||||
Interest rate swaps | — | 75,779 | — | — | — | 75,779 | ||||||||||||
Total | $ | — | $ | 82,514 | $ | — | $ | — | $ | — | $ | 82,514 |
Commodity Derivatives | Commodity Derivatives | |||||
December 31, 2011 | December 31, 2010 | |||||
Balance at beginning of year | $ | 266 | $ | 381 | ||
Unrealized losses | (1,318 | ) | (303 | ) | ||
Unrealized gains | 751 | 188 | ||||
Purchases | — | — | ||||
Issuances | — | — | ||||
Settlements | (96 | ) | — | |||
Transfers into level 3(a) | — | — | ||||
Transfers out of level 3 (b) | — | — | ||||
Balance at year end | $ | (397 | ) | $ | 266 | |
Changes in unrealized (losses) gain relating to instruments still held as of year end | $ | (101 | ) | $ | (302 | ) |
(a) | Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable. |
(b) | Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period. |
December 31, 2011 | December 31, 2010 | ||||||||||||
Balance Sheet Location | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | |||||||||
Derivatives designated as hedges: | |||||||||||||
Commodity derivatives | Derivative assets - current | $ | 8,739 | $ | — | $ | 7,923 | $ | — | ||||
Commodity derivatives | Derivative assets - non-current | 1,919 | — | 2,625 | — | ||||||||
Commodity derivatives | Derivative liabilities - current | — | 2,559 | — | 3,814 | ||||||||
Commodity derivatives | Derivative liabilities - non-current | — | 818 | — | 1,301 | ||||||||
Interest rate swaps | Derivative liabilities - current | — | 6,513 | — | 6,822 | ||||||||
Interest rate swaps | Derivative liabilities - non-current | — | 20,363 | — | 14,976 | ||||||||
$ | 10,658 | $ | 30,253 | $ | 10,548 | $ | 26,913 | ||||||
Derivatives not designated as hedges: | |||||||||||||
Commodity derivatives | Derivative assets - current | $ | — | $ | 9,572 | $ | — | $ | 5,567 | ||||
Commodity derivatives | Derivative assets - non-current | — | (52 | ) | — | — | |||||||
Commodity derivatives | Derivative liabilities - current | — | — | — | — | ||||||||
Commodity derivatives | Derivative liabilities - non-current | — | 7,156 | — | 1,621 | ||||||||
Interest rate swaps | Derivative liabilities - current | — | 75,295 | — | 53,980 | ||||||||
Interest rate swaps | Derivative liabilities - non-current | — | 20,696 | — | — | ||||||||
$ | — | $ | 112,667 | $ | — | $ | 61,168 |
December 31, 2011 | |||||||||||
Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | ||||||
Interest rate swaps | $ | (12,280 | ) | Interest expense | $ | (7,664 | ) | $ | — | ||
Commodity derivatives | 7,741 | Revenue | 5,487 | — | |||||||
Total | $ | (4,539 | ) | $ | (2,177 | ) | $ | — |
December 31, 2010 | |||||||||||
Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | ||||||
Interest rate swaps | $ | (13,527 | ) | Interest expense | $ | (7,609 | ) | $ | — | ||
Commodity derivatives | 15,456 | Revenue | 14,339 | — | |||||||
Total | $ | 1,929 | $ | 6,730 | $ | — |
December 31, 2009 | |||||||||||
Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | ||||||
Interest rate swaps | $ | 12,818 | Interest expense | $ | (3,292 | ) | $ | — | |||
Commodity derivatives | (21,070 | ) | Revenue | 23,102 | Revenue | (1,394 | ) | ||||
Total | $ | (8,252 | ) | $ | 19,810 | $ | (1,394 | ) |
December 31, 2011 | December 31, 2010 | December 31, 2009 | ||||||||
Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | ||||||
Interest rate swaps - unrealized | Unrealized gain (loss) on interest rate swap | $ | (42,010 | ) | $ | (15,193 | ) | $ | 55,653 | |
Interest rate swaps - realized | Interest expense | (13,373 | ) | (13,312 | ) | (9,816 | ) | |||
$ | (55,383 | ) | $ | (28,505 | ) | $ | 45,837 |
2011 | 2010 | |||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||
Cash and cash equivalents | $ | 21,628 | $ | 21,628 | $ | 16,437 | $ | 16,437 | ||||
Restricted cash | $ | 9,254 | $ | 9,254 | $ | 4,260 | $ | 4,260 | ||||
Total derivative assets | $ | 20,554 | $ | 20,554 | $ | 15,335 | $ | 15,335 | ||||
Total derivative liabilities | $ | 133,400 | $ | 133,400 | $ | 82,514 | $ | 82,514 | ||||
Notes payable | $ | 345,000 | $ | 345,000 | $ | 249,000 | $ | 249,000 | ||||
Long-term debt, including current maturities | $ | 1,282,882 | $ | 1,464,289 | $ | 1,191,231 | $ | 1,290,519 |
Utilities Group | 2011 | 2010 | Lives ( in years) | |||||||
Electric Utilities | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Minimum | Maximum | ||||
Electric plant: | ||||||||||
Production | $ | 707,498 | 49 | $ | 679,165 | 47 | 25 | 80 | ||
Electric transmission | 170,146 | 49 | 154,936 | 47 | 40 | 65 | ||||
Electric distribution | 580,699 | 45 | 543,498 | 43 | 15 | 65 | ||||
Plant acquisition adjustment | 4,870 | 32 | 4,870 | 32 | 32 | 32 | ||||
General | 136,304 | 22 | 103,455 | 20 | 3 | 60 | ||||
Capital lease - plant in service * | 260,874 | 20 | — | — | 20 | 20 | ||||
Construction work in progress | 288,760 | 234,985 | ||||||||
Total electric plant | 2,149,151 | 1,720,909 | ||||||||
Less accumulated depreciation and amortization | 385,840 | 357,774 | ||||||||
Electric plant net of accumulated depreciation and amortization | $ | 1,763,311 | $ | 1,363,135 |
* | Capital lease - plant in service represents the assets accounted for as a capital lease under the 20-year PPA between Colorado Electric and Black Hills Colorado IPP. |
2011 | 2010 | Lives (in years) | ||||||||
Gas Utilities | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Minimum | Maximum | ||||
Gas plant: | ||||||||||
Production | $ | 35 | 37 | $ | 35 | 37 | 37 | 37 | ||
Gas transmission | 15,543 | 53 | 15,704 | 48 | 53 | 57 | ||||
Gas distribution | 442,114 | 46 | 406,914 | 45 | 41 | 56 | ||||
General | 56,869 | 19 | 68,315 | 19 | 16 | 22 | ||||
Construction work in progress | 8,813 | 11,392 | ||||||||
Total gas plant | 523,374 | 502,360 | ||||||||
Less accumulated depreciation and amortization | 52,249 | 47,292 | ||||||||
Gas plant net of accumulated depreciation and amortization | $ | 471,125 | $ | 455,068 |
2011 | Lives ( in years) | ||||||||||||||
Non-regulated Energy | Property, Plant and Equipment | Construction Work in Progress | Less Accumulated Depreciation, Depletion and Amortization | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | ||||||||
Coal Mining | $ | 140,683 | $ | 4,341 | $ | 73,777 | $ | 71,247 | 20 | 2 | 39 | ||||
Oil and Gas | 763,645 | — | 386,377 | 377,268 | 25 | 3 | 26 | ||||||||
Power Generation | 135,051 | 930 | 35,074 | 100,907 | 36 | 2 | 40 | ||||||||
$ | 1,039,379 | $ | 5,271 | $ | 495,228 | $ | 549,422 |
2010 | Lives ( in years) | ||||||||||||||
Non-regulated Energy | Property, Plant and Equipment | Construction Work in Progress | Less Accumulated Depreciation, Depletion and Amortization | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | ||||||||
Coal Mining | $ | 135,157 | $ | 10,228 | $ | 65,465 | $ | 79,920 | 11 | 3 | 40 | ||||
Oil and Gas | 680,407 | — | 357,979 | 322,428 | 26 | 3 | 27 | ||||||||
Power Generation | 134,616 | 163,291 | 30,982 | 266,925 | 36 | 2 | 40 | ||||||||
$ | 950,180 | $ | 173,519 | $ | 454,426 | $ | 669,273 |
2011 | Lives ( in years) | |||||||||||||||
Property, Plant and Equipment | Construction Work in Progress | Less Accumulated Depreciation, Depletion and Amortization | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | ||||||||||
Corporate | $ | 2,136 | $ | 4,705 | $ | 1,124 | $ | 5,717 | 6 | 2 | 30 |
2010 | Lives (in years) | ||||||||||||||
Property, Plant and Equipment | Construction Work in Progress | Less Accumulated Depreciation, Depletion and Amortization | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | |||||||||
Corporate | $ | 4,039 | $ | 2,502 | $ | 2,283 | $ | 4,258 | 6 | 2 | 30 |
• | Our subsidiary, Black Hills Power, owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. Black Hills Power receives its proportionate share of the Wyodak Plant's capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying Black Hills Power with coal for its share of the Wyodak Plant, our Coal Mining subsidiary, WRDC, supplies PacifiCorp's share of the coal to the Wyodak Plant under a long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC's coal reserves. |
• | Black Hills Power also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the tie is 400 MW - 200 MW West to East and 200 MW from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie. |
• | Black Hills Power own 52% of its Wygen III coal-fired generation facility which commenced commercial operation on April 1, 2010. MDU and the City of Gillette each owns an undivided ownership interest in the Wygen III generation facility and are obligated to make payments for costs associated with administrative services and proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations. |
• | Black Hills Wyoming owns 76.5% of its Wygen I Plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for costs associated with administrative services, plant operations and coal supply provided by our Coal Mining subsidiary during the life of the facility. We retain responsibility for plant operations. |
Plant in Service | Construction Work in Progress | Accumulated Depreciation | |||||||
Wyodak Plant | $ | 109,007 | $ | 718 | $ | 46,104 | |||
Transmission Tie | 19,648 | — | 4,061 | ||||||
Wygen I | 104,854 | 880 | 23,046 | ||||||
Wygen III | 129,791 | 249 | 5,328 | ||||||
$ | 363,300 | $ | 1,847 | $ | 78,539 |
Due Date | Interest Rate | 2011 | 2010 | |||||
Corporate | ||||||||
Senior unsecured notes due 2013 | May 15, 2013 | 6.5% | $ | 225,000 | $ | 225,000 | ||
Unamortized discount on notes due 2013 | (41 | ) | (70 | ) | ||||
Senior unsecured notes due 2014 | May 15, 2014 | 9.0% | 250,000 | 250,000 | ||||
Senior unsecured notes due 2020 | July 15, 2020 | 5.88% | 200,000 | 200,000 | ||||
Long-term term loan (a) | September 30, 2013 | 1.69% | 100,000 | — | ||||
Total Corporate Debt | 774,959 | 674,930 | ||||||
Electric Utilities | ||||||||
First Mortgage Bonds due 2032 | August 15, 2032 | 7.23% | 75,000 | 75,000 | ||||
First Mortgage Bonds due 2039 | November 1, 2039 | 6.13% | 180,000 | 180,000 | ||||
Unamortized discount on First Mortgage Bonds due 2039 | (115 | ) | (119 | ) | ||||
Pollution control revenue bonds due 2014 | October 1, 2014 | 4.80% | 6,450 | 6,450 | ||||
Pollution control revenue bonds due 2024 | October 1, 2024 | 5.35% | 12,200 | 12,200 | ||||
First Mortgage Bonds due 2037 | November 20, 2037 | 6.67% | 110,000 | 110,000 | ||||
Industrial development revenue bonds due 2021, variable rate (a) | September 1, 2021 | 0.14% | 7,000 | 7,000 | ||||
Industrial development revenue bonds due 2027, variable rate (a) | March 1, 2027 | 0.14% | 10,000 | 10,000 | ||||
Series 94A Debt (a) | June 1, 2024 | 3.00% | 2,855 | 2,855 | ||||
Other long-term debt | May 12, 2012 | 13.66% | 72 | 234 | ||||
Total Electric Utilities | 403,462 | 403,620 | ||||||
Power Generation | ||||||||
Black Hills Wyoming project financing, variable rate (a) | December 9, 2016 | 3.66% | 104,461 | 112,681 | ||||
Total long-term debt | 1,282,882 | 1,191,231 | ||||||
Less current maturities | 2,473 | 5,181 | ||||||
Net long-term debt | $ | 1,280,409 | $ | 1,186,050 |
(a) | Variable interest rates, rates presented are as of December 31, 2011. |
2012 | $ | 2,473 | |
2013 | $ | 328,973 | |
2014 | $ | 262,473 | |
2015 | $ | 6,964 | |
2016 | $ | 85,101 | |
Thereafter | $ | 597,054 |
Deferred Financing Costs Remaining on Balance Sheet at | Amortization Expense for the years ended December 31, | |||||||||||
December 31, 2011 | 2011 | 2010 | 2009 | |||||||||
Senior unsecured notes due 2013 | $ | 309 | $ | 218 | $ | 218 | $ | 218 | ||||
Senior unsecured notes due 2014 | $ | 1,097 | $ | 462 | $ | 462 | $ | 289 | ||||
Senior unsecured notes due 2020 | $ | 1,428 | $ | 167 | $ | 77 | $ | — | ||||
First mortgage bonds due 2023 | $ | 684 | $ | 33 | $ | 33 | $ | 33 | ||||
First mortgage bonds due 2039 | $ | 2,113 | $ | 76 | $ | 76 | $ | 12 | ||||
First mortgage bonds due 2037 | $ | 797 | $ | 31 | $ | 31 | $ | 31 | ||||
Black Hills Wyoming project financing due 2016 | $ | 4,214 | $ | 1,012 | $ | 1,036 | $ | 60 | ||||
Other | $ | 816 | $ | 70 | $ | 74 | $ | 67 |
As of December 31, 2011 | As of December 31, 2010 | |||||||||||
Balance Outstanding | Letters of Credit | Balance Outstanding | Letters of Credit | |||||||||
Revolving Credit Facility | $ | 195,000 | $ | 43,700 | $ | 149,000 | $ | 46,865 | ||||
Term Loan 2011 | — | — | 100,000 | — | ||||||||
Term Loan 2012 | 150,000 | — | — | — | ||||||||
Total | $ | 345,000 | $ | 43,700 | $ | 249,000 | $ | 46,865 |
Deferred Financing Costs Remaining on Balance Sheet as of | Amortization Expense for the years ended December 31, | |||||||||||
December 31, 2011 | 2011 | 2010 | 2009 | |||||||||
Revolving Credit Facility | $ | 1,497 | $ | 1,891 | $ | 1,340 | $ | 495 |
Actual | Covenant Requirement | |||||
Consolidated net worth | $ | 1,209,336 | $ | 884,131 | ||
Recourse leverage ratio | 58.5 | % | 65.0 | % |
12/31/10 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates * | 12/31/11 | |||||||||||||
Oil and Gas | $ | 21,663 | $ | 43 | $ | (627 | ) | $ | 1,343 | $ | — | $ | 22,422 | |||||
Coal Mining | 17,560 | — | — | 1,123 | (1,525 | ) | 17,158 | |||||||||||
Electric Utilities | 3,039 | — | — | 25 | — | 3,064 | ||||||||||||
Gas Utilities | 255 | — | — | 15 | — | 270 | ||||||||||||
Total | $ | 42,517 | $ | 43 | $ | (627 | ) | $ | 2,506 | $ | (1,525 | ) | $ | 42,914 |
12/31/09 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates * | 12/31/10 | |||||||||||||
Oil and Gas | $ | 21,233 | $ | 570 | $ | (2,078 | ) | $ | 1,280 | $ | 658 | $ | 21,663 | |||||
Coal Mining | 15,285 | 18,094 | (15,207 | ) | 1,246 | (1,858 | ) | 17,560 | ||||||||||
Electric Utilities | 2,904 | — | — | 135 | — | 3,039 | ||||||||||||
Gas Utilities | 241 | — | — | 14 | — | 255 | ||||||||||||
Total | $ | 39,663 | $ | 18,664 | $ | (17,285 | ) | $ | 2,675 | $ | (1,200 | ) | $ | 42,517 |
* | The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium. |
2011 | 2010 | 2009 | |||||||
Stock-based compensation expense | $ | 5,643 | $ | 5,637 | $ | 3,908 |
Shares | Weighted-Average Exercise Price | Weighted-Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||
(in thousands) | (in years) | (in thousands) | ||||||||
Balance at beginning of period | 235 | $ | 32.92 | |||||||
Granted (a) | 99 | 32.04 | ||||||||
Forfeited/canceled | (6 | ) | — | |||||||
Expired | (31 | ) | 53.51 | |||||||
Exercised | (33 | ) | 30.32 | |||||||
Balance at end of period | 264 | $ | 30.50 | 4.5 | $ | 859 | ||||
Exercisable at end of period | 165 | $ | 29.57 |
(a) | The grant date fair value of the 2011 awards was $5.80 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.6% risk free interest rate, 29.0% expected price volatility, 4.6% expected dividend yield and a 7 year expected life. |
2011 | 2010 | 2009 | |||||||
Summary of Stock Options | |||||||||
Unrecognized compensation expense | $ | 479 | $ | — | $ | — | |||
Intrinsic value of options exercised (a) | $ | 94 | $ | 234 | $ | 255 | |||
Net cash received from exercise of options | $ | 1,009 | $ | 1,034 | $ | 1,740 | |||
Tax benefit realized from exercise of shares (b) | $ | 33 | $ | 82 | $ | 89 |
(a) | The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option. |
(b) | The tax benefit realized from the exercise of shares granted was recorded as an increase in equity. |
Restricted Stock and Stock Units | Weighted-Average Grant Date Fair Value | ||||
(in thousands) | |||||
Restricted Stock and Restricted Stock Units balance at beginning of period | 270 | $ | 27.78 | ||
Granted | 139 | 30.33 | |||
Vested | (113 | ) | 28.43 | ||
Forfeited | (18 | ) | 27.36 | ||
Restricted Stock and Restricted Stock Units balance at end of period | 278 | $ | 28.82 |
Weighted-Average Grant Date Fair Value | Total Fair Value of Shares Vested | |||||
(in thousands) | ||||||
2011 | $ | 30.33 | $ | 3,211 | ||
2010 | $ | 27.30 | $ | 2,212 | ||
2009 | $ | 26.76 | $ | 1,799 |
Grant Date | Performance Period | Target Grant of Shares |
January 1, 2009 | January 1, 2009 - December 31, 2011 | 73 |
January 1, 2010 | January 1, 2010 - December 31, 2012 | 71 |
January 1, 2011 | January 1, 2011 - December 31, 2013 | 67 |
Equity Portion | Liability Portion | |||||||||
Shares | Weighted-Average Grant Date Fair Value | Shares | Weighted-Average December 31, 2011 Fair Value | |||||||
(in thousands) | (in thousands) | |||||||||
Performance Shares balance at beginning of period | 87 | $ | 29.47 | 87 | ||||||
Granted | 34 | 25.92 | 34 | |||||||
Forfeited | (3 | ) | 25.77 | (3 | ) | |||||
Vested | (12 | ) | 46.00 | (12 | ) | |||||
Performance Shares balance at end of period | 106 | $ | 26.47 | 106 | $ | 20.89 |
Weighted Average Grant Date Fair Value | |||
December 31, 2011 | $ | 25.92 | |
December 31, 2010 | $ | 24.26 | |
December 31, 2009 | $ | 29.20 |
Performance Period | Year of Payment | Stock Issued | Cash Paid | Total Intrinsic Value | |||||
January 1, 2008 to December 31, 2010 | 2011 | — | $ | — | $ | — | |||
January 1, 2007 to December 31, 2009 | 2010 | — | $ | — | $ | — | |||
January 1, 2006 to December 31, 2008 | 2009 | — | $ | — | $ | — |
2011 | 2010 | |||||
Shares Issued | 103 | 106 | ||||
Weighted Average Price | $ | 31.23 | $ | 29.57 | ||
Unissued Shares Available at December 31 | 453 | 190 |
• | In connection with the Aquila Transaction, the CPUC, NPSC, IUB and KCC approved orders or settlement agreements providing that, among other things, (i) our utilities in those jurisdictions cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and (ii) neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. Covenants within Cheyenne Light's financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. In addition to the restrictions described above, each state in which we conduct utility operations imposes restrictions on affiliate transactions, including inter-company loans. Additionally, our utility subsidiaries are generally limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may be subject to further restrictions under the Federal Power Act. As of December 31, 2011, the restricted net assets at our Electric and Gas Utilities were approximately $61.5 million. |
• | Pursuant to a covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted assets of $100.0 million. In addition, Black Hills Wyoming holds $9.3 million of restricted cash in accordance with project financing requirements. Black Hills Non-regulated Holdings is the parent of Black Hills Electric Generation, which is the parent of Black Hills Wyoming. |
2011 | 2010 | 2009 | |||||||
Rent expense | $ | 6,125 | $ | 4,219 | $ | 3,939 |
2012 | $ | 2,799 | |
2013 | 2,398 | ||
2014 | 2,376 | ||
2015 | 1,912 | ||
2016 | 1,403 | ||
Thereafter | 3,610 | ||
$ | 14,498 |
2011 | 2010 | 2009 | |||||||
Current: | |||||||||
Current federal income tax expense (benefit) | $ | (14,539 | ) | $ | 678 | $ | (12,351 | ) | |
Current state income tax expense (benefit) | (837 | ) | 4,137 | (408 | ) | ||||
(15,376 | ) | 4,815 | (12,759 | ) | |||||
Deferred: | |||||||||
Deferred federal income tax expense (benefit) | 30,876 | 20,186 | 45,912 | ||||||
Deferred state income tax expense (benefit) | 2,970 | (2,495 | ) | 66 | |||||
Tax credit amortization expense (benefit) | (246 | ) | (337 | ) | (368 | ) | |||
33,600 | 17,354 | 45,610 | |||||||
Total income tax expense (benefit) | $ | 18,224 | $ | 22,169 | $ | 32,851 |
2011 | 2010 | |||||
Deferred tax assets, current: | ||||||
Asset valuation reserves | $ | 2,605 | $ | 1,448 | ||
Mining development and oil exploration | 614 | 594 | ||||
Unbilled revenue | — | — | ||||
Employee benefits | 8,175 | 3,899 | ||||
Items of other comprehensive income (loss) | 2,858 | 3,076 | ||||
Derivative fair value adjustments | 33,824 | 19,304 | ||||
Deferred costs | 97 | 342 | ||||
Other deferred tax assets, current | 4,493 | 5,607 | ||||
Total deferred tax assets, current | 52,666 | 34,270 | ||||
Deferred tax liabilities, current: | ||||||
Asset valuation reserves | — | (312 | ) | |||
Prepaid expenses | (2,442 | ) | (2,431 | ) | ||
Derivative fair value adjustments | (362 | ) | (327 | ) | ||
Items of other comprehensive income (loss) | (3,035 | ) | (2,754 | ) | ||
Deferred costs | (6,508 | ) | (4,621 | ) | ||
Other deferred tax liabilities, current | (3,117 | ) | (3,161 | ) | ||
Total deferred tax liabilities, current | (15,464 | ) | (13,606 | ) | ||
Net deferred tax asset, current | $ | 37,202 | $ | 20,664 | ||
Deferred tax assets, non-current: | ||||||
Employee benefits | $ | 14,313 | $ | 11,533 | ||
Regulatory liabilities | 40,642 | 23,910 | ||||
Deferred revenue | 225 | 273 | ||||
Deferred costs | — | — | ||||
State net operating loss (net of valuation allowance) | 11,538 | 9,507 | ||||
Items of other comprehensive income | 33,540 | 22,306 | ||||
Foreign tax credit carryover | 2,801 | 3,352 | ||||
Net operating loss | 195,834 | 63,779 | ||||
Asset impairment | 47,033 | 48,092 | ||||
Derivative fair value adjustment | 5,275 | 3,038 | ||||
Other deferred tax assets, non-current | 9,453 | 11,076 | ||||
Total deferred tax assets, non-current | 360,654 | 196,866 | ||||
Deferred tax liabilities, non-current: | ||||||
Accelerated depreciation, amortization and other plant-related differences | (508,261 | ) | (314,513 | ) | ||
Regulatory assets | (23,498 | ) | (16,050 | ) | ||
Mining development and oil exploration | (94,334 | ) | (99,709 | ) | ||
Deferred costs | (9,155 | ) | (17,615 | ) | ||
Derivative fair value adjustments | — | — | ||||
Items of other comprehensive income | (2,054 | ) | (4,402 | ) | ||
State deferred tax liability | (14,611 | ) | (11,477 | ) | ||
Other deferred tax liabilities, non-current | (9,729 | ) | (8,942 | ) | ||
Total deferred tax liabilities, non-current | (661,642 | ) | (472,708 | ) | ||
Net deferred tax liability, net, non-current | $ | (300,988 | ) | $ | (275,842 | ) |
Net deferred tax liability | $ | (263,786 | ) | $ | (255,178 | ) |
2011 | 2010 | |||||
Net increase (decrease) in net deferred income tax liability for the year | $ | 8,608 | $ | 414 | ||
Deferred taxes associated with other comprehensive loss (income) | 2,259 | 1,915 | ||||
Deferred taxes related to net operating loss from acquisition | — | (312 | ) | |||
Deferred taxes related to regulatory assets and liabilities | 22,962 | 25,511 | ||||
Deferred taxes related to acquisition | — | (784 | ) | |||
Deferred taxes associated with property basis differences | (14 | ) | (10,121 | ) | ||
Other net deferred income tax | (215 | ) | 731 | |||
Deferred income tax expense for the period | $ | 33,600 | $ | 17,354 |
2011 | 2010 | 2009 | ||||
Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % |
State income tax (net of federal tax effect) | 1.8 | 1.1 | (0.3 | ) | ||
Amortization of excess deferred and investment tax credits | (0.5 | ) | (0.4 | ) | (0.3 | ) |
Percentage depletion in excess of cost | (2.5 | ) | (1.7 | ) | (0.8 | ) |
Equity AFUDC | (0.5 | ) | (1.0 | ) | (1.7 | ) |
Tax credits | — | (3.2 | ) | — | ||
Accounting for uncertain tax positions adjustment | 2.8 | 1.2 | (2.1 | ) | ||
Flow-through adjustments * | (4.5 | ) | (4.6 | ) | — | |
Other tax differences | (0.5 | ) | (0.4 | ) | (0.3 | ) |
31.1 | % | 26.0 | % | 29.5 | % |
* | The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will continue to be capitalized for book purposes. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. Due to this regulatory treatment, we recorded an income tax benefit that was attributable to the 2008 through 2010 tax years. For years prior to 2008, we did not record a regulatory asset for the repairs deduction as the tax benefit was not flowed through to customers. |
Expiration Years | Net Operating Loss Carryforward | |||
2014-2019 | $ | 9,306 | ||
2020-2025 | $ | 48,229 | ||
2026-2031 | $ | 890,861 |
Changes in Uncertain Tax Positions | |||
Beginning balance at January 1, 2009 | $ | 120,022 | |
Additions for prior year tax positions | 5,752 | ||
Reductions for prior year tax positions | (18,686 | ) | |
Additions for current year tax positions | — | ||
Settlements | — | ||
Ending balance at December 31, 2009 | 107,088 | ||
Additions for prior year tax positions | 19,592 | ||
Reductions for prior year tax positions | (76,545 | ) | |
Additions for current year tax positions | — | ||
Settlements | — | ||
Ending balance at December 31, 2010 | 50,135 | ||
Additions for prior year tax positions | 2,725 | ||
Reductions for prior year tax positions | (3,533 | ) | |
Additions for current year tax positions | — | ||
Settlements | — | ||
Ending balance at December 31, 2011 | $ | 49,327 |
2011 | 2010 | 2009 | |||||||
Uncertain tax positions | $ | 49,327 | $ | 50,135 | $ | 107,088 | |||
Income tax refund receivable related to uncertain tax positions above | — | — | (59,136 | ) | |||||
Net liability for uncertain tax positions | $ | 49,327 | $ | 50,135 | $ | 47,952 |
2011 | 2010 | 2009 | |||||||
Interest expense (income) included in Income tax (expense) benefit | $ | 1,400 | $ | 2,300 | $ | 1,200 |
Foreign Tax Credit Carryforward | Expiration Year | |||
$ | 26 | 2014 | ||
$ | 694 | 2015 | ||
$ | 24 | 2016 | ||
$ | 1,301 | 2017 | ||
$ | 214 | 2020 | ||
$ | 542 | 2021 |
2011 | Pre-tax Amount | Tax (Expense) Benefit | Net-of-tax Amount | ||||||||
Benefit plan liability adjustments - net gains (losses) | $ | (11,744 | ) | $ | 4,135 | $ | (7,609 | ) | |||
Benefit plan liability adjustments - prior service (costs) | (501 | ) | 176 | (325 | ) | ||||||
Fair value adjustment of derivatives designated as cash flow hedges | (4,539 | ) | 1,708 | (2,831 | ) | ||||||
Reclassification adjustments of cash flow hedges settled and included in net income (loss) | 2,177 | (709 | ) | 1,468 | |||||||
Other comprehensive income (loss) | $ | (14,607 | ) | $ | 5,310 | $ | (9,297 | ) |
2010 | Pre-tax Amount | Tax (Expense) Benefit | Net-of-tax Amount | ||||||||
Benefit plan liability adjustments - net gains (losses) | $ | (1,981 | ) | $ | 674 | $ | (1,307 | ) | |||
Benefit plan liability adjustments - prior service (costs) | (325 | ) | 111 | (214 | ) | ||||||
Fair value adjustment of derivatives designated as cash flow hedges | 1,972 | (636 | ) | 1,336 | |||||||
Reclassification adjustments of cash flow hedges settled and included in net income (loss) | (6,730 | ) | 2,498 | (4,232 | ) | ||||||
Other comprehensive income (loss) | $ | (7,064 | ) | $ | 2,647 | $ | (4,417 | ) |
2009 | Pre-tax Amount | Tax (Expense) Benefit Plans | Net-of-tax Amount | ||||||||
Benefit plan liability adjustments - net gains (losses) | $ | (2,313 | ) | $ | 812 | $ | (1,501 | ) | |||
Benefit plan liability adjustments - prior service (costs) | 9,202 | (3,231 | ) | 5,971 | |||||||
Benefit plan liability adjustments - transition obligations | 33 | (12 | ) | 21 | |||||||
Fair value adjustment of derivatives designated as cash flow hedges | (27,442 | ) | 9,961 | (17,481 | ) | ||||||
Reclassification adjustments of cash flow hedges settled and included in net income (loss) | 19,810 | (7,201 | ) | 12,609 | |||||||
Other comprehensive income (loss) | $ | (710 | ) | $ | 329 | $ | (381 | ) |
Derivatives Designated as Cash Flow Hedges | Employee Benefit Plans | Amount from Equity-method Investees | Total | |||||||||
As of December 31, 2009 | $ | (9,462 | ) | $ | (9,636 | ) | $ | (66 | ) | $ | (19,164 | ) |
Other comprehensive income (loss) | (2,975 | ) | (1,506 | ) | 64 | (4,417 | ) | |||||
As of December 31, 2010 | $ | (12,437 | ) | $ | (11,142 | ) | $ | (2 | ) | $ | (23,581 | ) |
Other comprehensive income (loss) | (1,363 | ) | (7,934 | ) | — | (9,297 | ) | |||||
As of December 31, 2011 | $ | (13,800 | ) | $ | (19,076 | ) | $ | (2 | ) | $ | (32,878 | ) |
Years ended December 31, | 2011 | 2010 | 2009 | ||||||||
(in thousands) | |||||||||||
Non-cash investing and financing activities- | |||||||||||
Property, plant and equipment acquired with accrued liabilities | $ | 37,529 | $ | 48,879 | $ | 24,571 | |||||
Capitalized asset retirement costs | $ | 1,525 | $ | 1,858 | $ | 6,027 | |||||
Refunding bond issuance — Industrial Development Revenue Bonds | $ | — | $ | — | $ | 17,000 | |||||
Cash (paid) refunded during the period for- | |||||||||||
Interest (net of amount capitalized) | $ | (103,110 | ) | $ | (101,947 | ) | $ | (69,317 | ) | ||
Income taxes, net | $ | 9,854 | $ | 9,384 | $ | 17,117 |
2011 | 2010 | |||||
Total assets | ||||||
Utilities: | ||||||
Electric Utilities (a) | $ | 2,254,914 | $ | 1,834,019 | ||
Gas Utilities | 746,444 | 722,287 | ||||
Non-regulated Energy: | ||||||
Oil and Gas | 425,970 | 349,991 | ||||
Power Generation (a) | 129,121 | 293,334 | ||||
Coal Mining | 88,704 | 96,962 | ||||
Corporate | 141,079 | 100,681 | ||||
Discontinued Operations | 340,851 | 314,235 | ||||
Total assets | $ | 4,127,083 | $ | 3,711,509 |
(a) | The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease. |
2011 | 2010 | |||||
Capital expenditures and asset acquisitions | ||||||
Utilities: | ||||||
Electric Utilities | $ | 173,078 | $ | 232,466 | ||
Gas Utilities | 43,954 | 51,363 | ||||
Non-regulated Energy: | ||||||
Oil and Gas | 89,672 | 40,345 | ||||
Power Generation | 98,927 | 148,191 | ||||
Coal Mining | 10,438 | 17,053 | ||||
Corporate | 13,279 | 7,182 | ||||
Total capital expenditures and asset acquisitions of continuing operations(a) | 429,348 | 496,600 | ||||
Total capital expenditures of discontinued operations | 2,359 | 390 | ||||
Total capital expenditures and asset acquisitions | $ | 431,707 | $ | 496,990 |
(a) | Includes accruals for property, plant and equipment. |
2011 | 2010 | |||||
Property, plant and equipment | ||||||
Utilities: | ||||||
Electric Utilities (a) | $ | 2,149,151 | $ | 1,720,909 | ||
Gas Utilities | 523,374 | 502,360 | ||||
Non-regulated Energy: | ||||||
Oil and Gas | 763,645 | 680,407 | ||||
Power Generation (a) | 135,981 | 297,907 | ||||
Coal Mining | 145,024 | 145,385 | ||||
Corporate | 6,841 | 6,541 | ||||
Total property, plant and equipment | $ | 3,724,016 | $ | 3,353,509 |
(a) | The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease. |
Consolidating Income Statement | ||||||||||||||||||||||||
Year ended December 31, 2011 | Electric Utilities | Gas Utilities | Power Generation | Coal Mining | Oil and Gas | Corporate | Intercompany Eliminations | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Revenue | $ | 600,935 | $ | 554,584 | $ | 4,059 | $ | 32,802 | $ | 79,808 | $ | — | $ | — | $ | 1,272,188 | ||||||||
Intercompany revenue | 13,396 | — | 27,613 | 34,090 | — | 192,250 | (267,349 | ) | — | |||||||||||||||
Fuel, purchased power and cost of gas sold | 310,352 | 331,961 | — | — | — | 97 | (67,421 | ) | 574,989 | |||||||||||||||
Gross margin | 303,979 | 222,623 | 31,672 | 66,892 | 79,808 | 192,153 | (199,928 | ) | 697,199 | |||||||||||||||
Operations and maintenance | 142,815 | 121,980 | 16,538 | 56,617 | 41,380 | 170,947 | (174,908 | ) | 375,369 | |||||||||||||||
Gain on sale of operating assets (a) | (768 | ) | — | — | — | — | 1 | 767 | — | |||||||||||||||
Depreciation, depletion and amortization | 52,475 | 24,307 | 4,199 | 18,670 | 35,690 | 11,205 | (10,955 | ) | 135,591 | |||||||||||||||
Operating income (loss) | 109,457 | 76,336 | 10,935 | (8,395 | ) | 2,738 | 10,000 | (14,832 | ) | 186,239 | ||||||||||||||
Interest expense | (53,770 | ) | (31,621 | ) | (8,903 | ) | (9 | ) | (5,896 | ) | (93,314 | ) | 102,130 | (91,383 | ) | |||||||||
Unrealized (loss) gain on interest rate swaps, net | — | — | — | — | — | (42,010 | ) | — | (42,010 | ) | ||||||||||||||
Interest income | 14,794 | 5,645 | 1,529 | 3,897 | 2 | 64,299 | (88,149 | ) | 2,017 | |||||||||||||||
Other income (expense), net | 481 | 217 | 1,094 | 2,192 | (216 | ) | 46,510 | (46,552 | ) | 3,726 | ||||||||||||||
Income tax benefit (expense) | (23,271 | ) | (16,408 | ) | (1,644 | ) | 1,891 | 1,651 | 19,289 | 268 | (18,224 | ) | ||||||||||||
Income (loss) from continuing operations | $ | 47,691 | $ | 34,169 | $ | 3,011 | $ | (424 | ) | $ | (1,721 | ) | $ | 4,774 | $ | (47,135 | ) | $ | 40,365 |
(a) | Electric Utilities includes a gain on sale of assets to a related party which was eliminated in consolidation. |
Consolidating Income Statement | ||||||||||||||||||||||||
Year ended December 31, 2010 | Electric Utilities | Gas Utilities | Power Generation | Coal Mining | Oil and Gas | Corporate | Intercompany Eliminations | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Revenue (a) | $ | 554,617 | $ | 550,707 | $ | 4,297 | $ | 31,285 | $ | 74,164 | $ | — | $ | — | $ | 1,215,070 | ||||||||
Intercompany revenue (a) | 15,397 | — | 26,052 | 26,557 | — | 140,756 | (204,141 | ) | 4,621 | |||||||||||||||
Fuel, purchased power and cost of gas sold (a) | 292,811 | 333,717 | — | — | — | 150 | (59,711 | ) | 566,967 | |||||||||||||||
Gross margin | 277,203 | 216,990 | 30,349 | 57,842 | 74,164 | 140,606 | (144,430 | ) | 652,724 | |||||||||||||||
Operations and maintenance | 136,873 | 125,447 | 16,210 | 34,028 | 39,299 | 129,641 | (129,879 | ) | 351,619 | |||||||||||||||
Gain on sale of operating assets (b) | (6,238 | ) | (2,683 | ) | — | — | — | — | — | (8,921 | ) | |||||||||||||
Depreciation, depletion and amortization | 47,276 | 25,258 | 4,466 | 19,083 | 30,283 | 9,469 | (9,229 | ) | 126,606 | |||||||||||||||
Operating income (loss) | 99,292 | 68,968 | 9,673 | 4,731 | 4,582 | 1,496 | (5,322 | ) | 183,420 | |||||||||||||||
Interest expense | (43,855 | ) | (28,927 | ) | (9,303 | ) | (177 | ) | (5,380 | ) | (75,406 | ) | 72,442 | (90,606 | ) | |||||||||
Unrealized (loss) gain on interest rate swaps, net | — | — | — | — | — | (15,193 | ) | — | (15,193 | ) | ||||||||||||||
Interest income | 6,812 | 1,472 | 1,193 | 3,357 | 8 | 54,472 | (66,773 | ) | 541 | |||||||||||||||
Other income (expense), net | 3,215 | 47 | 854 | 2,149 | 722 | 28,768 | (28,607 | ) | 7,148 | |||||||||||||||
Income tax benefit (expense) | (18,012 | ) | (14,449 | ) | (266 | ) | (2,379 | ) | 425 | 12,512 | — | (22,169 | ) | |||||||||||
Income (loss) from continuing operations | $ | 47,452 | $ | 27,111 | $ | 2,151 | $ | 7,681 | $ | 357 | $ | 6,649 | $ | (28,260 | ) | $ | 63,141 |
(a) | Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1). |
(b) | Electric Utilities includes gain on sale to the City of Gillette of an ownership interest in the Wygen III power generation facility. Gas Utilities includes a gain on the sale of operating assets at Nebraska Gas (see Note 22). |
Consolidating Income Statement | ||||||||||||||||||||||||
Year ended December 31, 2009 | Electric Utilities | Gas Utilities | Power Generation | Coal Mining | Oil and Gas | Corporate | Intercompany Eliminations | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Revenue (a) | $ | 511,326 | $ | 580,312 | $ | 4,445 | $ | 31,459 | $ | 70,684 | $ | — | $ | — | $ | 1,198,226 | ||||||||
Intercompany revenue (a) | 9,439 | — | 26,130 | 27,031 | — | 97,010 | (159,124 | ) | 486 | |||||||||||||||
Fuel, purchased power and cost of gas sold (a) | 281,009 | 371,716 | — | — | — | 1 | (57,486 | ) | 595,240 | |||||||||||||||
Gross margin | 239,756 | 208,596 | 30,575 | 58,490 | 70,684 | 97,009 | (101,638 | ) | 603,472 | |||||||||||||||
Operations and maintenance | 125,150 | 123,296 | 12,631 | 40,312 | 40,224 | 95,184 | (95,748 | ) | 341,049 | |||||||||||||||
Gain on sale of operating assets (b) | — | — | (25,971 | ) | — | — | — | — | (25,971 | ) | ||||||||||||||
Depreciation, depletion and amortization | 43,638 | 30,090 | 3,860 | 13,123 | 29,680 | 6,933 | (6,386 | ) | 120,938 | |||||||||||||||
Impairment of long-lived assets (c) | — | — | — | — | 43,301 | — | — | 43,301 | ||||||||||||||||
Operating income | 70,968 | 55,210 | 40,055 | 5,055 | (42,521 | ) | (5,108 | ) | 496 | 124,155 | ||||||||||||||
Interest expense | (34,830 | ) | (17,364 | ) | (11,244 | ) | (24 | ) | (4,683 | ) | (47,522 | ) | 32,414 | (83,253 | ) | |||||||||
Unrealized (loss) gain on interest rate swaps, net | — | — | — | — | — | 55,653 | — | 55,653 | ||||||||||||||||
Interest income | 1,818 | 264 | 1,856 | 1,476 | 10 | 27,531 | (32,032 | ) | 923 | |||||||||||||||
Other income (expense), net | 7,869 | (285 | ) | 1,091 | 3,475 | 350 | 12,201 | (12,059 | ) | 12,642 | ||||||||||||||
Income tax benefit (expense) | (13,126 | ) | (13,453 | ) | (11,097 | ) | (3,234 | ) | 21,016 | (12,957 | ) | — | (32,851 | ) | ||||||||||
Income (loss) from continuing operations | $ | 32,699 | $ | 24,372 | $ | 20,661 | $ | 6,748 | $ | (25,828 | ) | $ | 29,798 | $ | (11,181 | ) | $ | 77,269 |
(a) | Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1). |
(b) | Includes a gain on sale to MEAN of an ownership interest in the Wygen I power generation facility (see Note 22). |
(c) | As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets (see Note 12). |
2011 | 2010 | |||
Equity | 64 | % | 65 | % |
Real estate | 3 | 3 | ||
Fixed income | 32 | 31 | ||
Cash | 1 | 1 | ||
Total | 100 | % | 100 | % |
2011 | 2010 | |||||
Defined Benefit Plans | ||||||
Defined Benefit Pension Plans | $ | 11,050 | $ | 30,015 | ||
Non-Pension Defined Benefit Postretirement Healthcare Plans | $ | 4,963 | $ | 5,198 | ||
Supplemental Non-Qualified Defined Benefit Plans | $ | 956 | $ | 894 |
2011 | 2010 | |||||
Defined Contribution Plan | ||||||
Company Retirement Contribution | $ | 2,440 | $ | 2,022 | ||
Matching contributions - Defined Contribution Plans | $ | 8,916 | $ | 7,900 |
2012 | |||
Defined Benefit Plans | |||
Defined Benefit Pension Plans | $ | 12,483 | |
Non-Pension Defined Benefit Postretirement Healthcare Plans | $ | 4,250 | |
Supplemental Non-Qualified Defined Benefit Plans | $ | 1,110 |
Defined Benefit Pension Plans | December 31, 2011 | ||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Money Market Fund | $ | 70 | $ | — | $ | — | $ | 70 | |||||||
Registered Investment Companies - Equity | 23,498 | — | — | 23,498 | |||||||||||
Registered Investment Companies - Fixed Income | 23,422 | — | — | 23,422 | |||||||||||
103-12 Investment Entities - Equity | — | 10,329 | — | 10,329 | |||||||||||
Common Collective Trust - Money Market | — | 25 | — | 25 | |||||||||||
Common Collective Trust - Equity | — | 103,004 | — | 103,004 | |||||||||||
Common Collective Trust - Fixed Income | — | 48,024 | — | 48,024 | |||||||||||
Common Collective Trust - Real Estate | — | — | 7,042 | 7,042 | |||||||||||
Structured Products | — | 3,884 | — | 3,884 | |||||||||||
Insurance Contracts | — | 2,424 | — | 2,424 | |||||||||||
Total investments measured at fair value | $ | 46,990 | $ | 167,690 | $ | 7,042 | $ | 221,722 |
Defined Benefit Pension Plans | December 31, 2010 | ||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Money Market Fund | $ | — | $ | — | $ | — | $ | — | |||||||
Registered Investment Companies - Equity | 27,070 | — | — | 27,070 | |||||||||||
Registered Investment Companies - Fixed Income | 27,544 | — | — | 27,544 | |||||||||||
103-12 Investment Entities - Equity | — | 11,246 | — | 11,246 | |||||||||||
Common Collective Trust - Money Market | — | 174 | — | 174 | |||||||||||
Common Collective Trust - Equity | — | 106,786 | — | 106,786 | |||||||||||
Common Collective Trust - Fixed Income | — | 39,121 | — | 39,121 | |||||||||||
Common Collective Trust - Real Estate | — | — | 6,126 | 6,126 | |||||||||||
Insurance Contracts | — | 2,097 | — | 2,097 | |||||||||||
Total investments measured at fair value | $ | 54,614 | $ | 159,424 | $ | 6,126 | $ | 220,164 |
Non-pension Defined Benefit Postretirement Plans | December 31, 2011 | ||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Common Collective Trust | $ | — | $ | 4,319 | $ | — | $ | 4,319 | |||||||
Total investments measured at fair value | $ | — | $ | 4,319 | $ | — | $ | 4,319 |
Non-pension Defined Benefit Postretirement Plan | December 31, 2010 | ||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Common Collective Trust | $ | — | $ | 4,564 | $ | — | $ | 4,564 | |||||||
Total investments measured at fair value | $ | — | $ | 4,564 | $ | — | $ | 4,564 |
2011 | 2010 | |||||
Balance, beginning of period | $ | 6,126 | $ | 5,844 | ||
Unrealized gain (loss) | 917 | 282 | ||||
Balance, end of period | $ | 7,043 | $ | 6,126 |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | ||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||
Change in benefit obligation: | ||||||||||||||||||||
Projected benefit obligation at beginning of year | $ | 280,623 | $ | 256,400 | $ | 24,725 | $ | 21,611 | $ | 46,304 | $ | 46,396 | ||||||||
Service cost | 5,421 | 6,131 | 1,028 | 685 | 1,498 | 1,509 | ||||||||||||||
Interest cost | 14,929 | 15,091 | 1,298 | 1,284 | 2,168 | 2,446 | ||||||||||||||
Actuarial (gain) loss | 36,543 | 13,663 | 4,128 | 2,039 | 3,017 | 961 | ||||||||||||||
Amendments | — | 261 | — | — | (160 | ) | (2,239 | ) | ||||||||||||
Benefits paid | (11,178 | ) | (9,949 | ) | (956 | ) | (894 | ) | (4,963 | ) | (5,198 | ) | ||||||||
Plan curtailment reduction | (394 | ) | (974 | ) | — | — | — | — | ||||||||||||
Medicare Part D accrued | — | — | — | — | 188 | 559 | ||||||||||||||
Plan participants' contributions | — | — | — | — | 2,089 | 1,870 | ||||||||||||||
Projected benefit obligation at end of year | $ | 325,944 | $ | 280,623 | $ | 30,223 | $ | 24,725 | $ | 50,141 | $ | 46,304 |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans (a) | ||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||
Beginning market value of plan assets | $ | 220,164 | $ | 176,503 | $ | — | $ | — | $ | 4,564 | $ | 4,717 | ||||||||
Investment income | 1,686 | 23,595 | — | — | 1 | 1 | ||||||||||||||
Employer contributions | 11,050 | 30,015 | — | — | 2,087 | 2,493 | ||||||||||||||
Retiree contributions | — | — | — | — | 1,366 | 1,205 | ||||||||||||||
Benefits paid | (11,178 | ) | (9,949 | ) | — | — | (3,713 | ) | (3,847 | ) | ||||||||||
Plan administrative expenses | — | — | — | — | 14 | (5 | ) | |||||||||||||
Ending market value of plan assets | $ | 221,722 | $ | 220,164 | $ | — | $ | — | $ | 4,319 | $ | 4,564 |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | ||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||
Regulatory asset | $ | 93,423 | $ | 54,202 | $ | — | $ | — | $ | 9,161 | $ | 7,896 | ||||||||
Current liability | $ | — | $ | — | $ | 1,116 | $ | 943 | $ | 3,522 | $ | 2,999 | ||||||||
Non-current liability | $ | 104,214 | $ | 60,451 | $ | 30,953 | $ | 23,782 | $ | 42,313 | $ | 38,561 | ||||||||
Regulatory liability | $ | — | $ | — | $ | — | $ | — | $ | 590 | $ | 1,050 |
(in thousands) | Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||
Accumulated benefit obligation - Black Hills Corporation | $ | 106,800 | $ | 90,301 | $ | 23,023 | $ | 19,153 | $ | 14,313 | $ | 12,101 | ||||||||
Accumulated benefit obligation - Black Hills Energy | 184,345 | 160,217 | 446 | 454 | 25,842 | 25,080 | ||||||||||||||
Accumulated benefit obligation - Cheyenne Light | 5,731 | 4,462 | — | — | 9,986 | 9,121 | ||||||||||||||
$ | 296,876 | $ | 254,980 | $ | 23,469 | $ | 19,607 | $ | 50,141 | $ | 46,302 |
(in thousands) | Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | ||||||||||||||||||||||||||
2011 | 2010 | 2009 | 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||||||||||||
Service cost | $ | 5,421 | $ | 6,131 | $ | 7,587 | $ | 1,028 | $ | 685 | $ | 469 | $ | 1,498 | $ | 1,509 | $ | 1,060 | |||||||||||
Interest cost | 14,929 | 15,091 | 14,715 | 1,298 | 1,284 | 1,376 | 2,168 | 2,446 | 2,202 | ||||||||||||||||||||
Expected return on assets | (16,955 | ) | (14,493 | ) | (14,281 | ) | — | — | — | (164 | ) | (208 | ) | (226 | ) | ||||||||||||||
Amortization of prior service cost | 99 | 99 | 127 | 3 | 3 | 1 | (479 | ) | (309 | ) | (23 | ) | |||||||||||||||||
Amortization of transition obligation | — | — | — | — | — | — | — | — | 60 | ||||||||||||||||||||
Recognized net actuarial loss (gain) | 4,540 | 3,126 | 2,720 | 510 | 285 | 589 | 677 | 636 | (27 | ) | |||||||||||||||||||
Curtailment expense | 13 | 57 | 322 | — | — | — | — | — | — | ||||||||||||||||||||
Net periodic expense | $ | 8,047 | $ | 10,011 | $ | 11,190 | $ | 2,839 | $ | 2,257 | $ | 2,435 | $ | 3,700 | $ | 4,074 | $ | 3,046 |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | ||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||
Net (gain) loss | $ | 11,472 | $ | 6,545 | $ | 6,894 | $ | 4,544 | $ | 2,556 | $ | 2,172 | ||||||||
Prior service cost (gain) | 98 | 121 | 12 | 14 | (1,956 | ) | (2,276 | ) | ||||||||||||
Transition obligation | — | — | — | — | — | — | ||||||||||||||
Total accumulated other comprehensive (income) loss | $ | 11,570 | $ | 6,666 | $ | 6,906 | $ | 4,558 | $ | 600 | $ | (104 | ) |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | |||||||||
Net loss | $ | 6,560 | $ | 525 | $ | 577 | |||||
Prior service cost | 58 | 2 | (325 | ) | |||||||
Transition obligation | — | — | — | ||||||||
Total net periodic benefit cost expected to be recognized during calendar year 2012 | $ | 6,618 | $ | 527 | $ | 252 |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | ||||||||||||||||||
Weighted-average assumptions used to determine benefit obligations: | 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||
Discount rate | 4.65 | % | 5.48 | % | 6.03 | % | 4.30 | % | 4.95 | % | 5.58 | % | 4.42 | % | 5.03 | % | 5.68 | % | ||
Rate of increase in compensation levels | 3.77 | % | 3.79 | % | 4.20 | % | 5.00 | % | 5.00 | % | 5.00 | % | N/A | N/A | N/A |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans | ||||||||||||||||||
Weighted-average assumptions used to determine net periodic benefit cost for plan year: | 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||
Discount rate: | ||||||||||||||||||||
Black Hills Corporation | 5.50 | % | 6.05 | % | 6.25 | % | 5.00 | % | 6.10 | % | 6.20 | % | 5.00 | % | 5.90 | % | 6.10 | % | ||
Black Hills Energy | 5.40 | % | 6.00 | % | 6.25 | % | 4.40 | % | 5.05 | % | 5.00 | % | 4.60 | % | 5.15 | % | 6.10 | % | ||
Cheyenne Light | 5.55 | % | 6.05 | % | 6.20 | % | N/A | N/A | N/A | 5.50 | % | 6.00 | % | 6.10 | % | |||||
Expected long-term rate of return on assets* | 7.75 | % | 8.00 | % | 8.50 | % | N/A | N/A | N/A | 4.00 | % | 5.00 | % | 5.00 | % | |||||
Rate of increase in compensation levels | 3.79 | % | 4.20 | % | 4.20 | % | 5.00 | % | 5.00 | % | 5.00 | % | NA | NA | N/A |
* | The expected rate of return on plan assets changed to 7.25% for the calculation of the 2012 net periodic pension cost. |
Change in Assumed Trend Rate | Impact on December 31, 2011 Accumulated Postretirement Benefit Obligation | Impact on 2011 Service and Interest Cost | ||||||
Increase 1% | $ | 2,720 | $ | 184 | ||||
Decrease 1% | $ | (2,272 | ) | $ | (150 | ) |
Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plan | Non-Pension Defined Benefit Postretirement Plans | |||||||||
2012 | $ | 12,484 | $ | 1,110 | $ | 4,250 | |||||
2013 | $ | 13,181 | $ | 1,090 | $ | 4,380 | |||||
2014 | $ | 13,953 | $ | 1,280 | $ | 4,320 | |||||
2015 | $ | 14,823 | $ | 1,290 | $ | 4,170 | |||||
2016 | $ | 15,694 | $ | 1,370 | $ | 4,250 | |||||
2017-2021 | $ | 93,852 | $ | 7,160 | $ | 21,950 |
• | Black Hills Power's PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp's system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants. |
• | Black Hills Power has a firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp. |
• | Cheyenne Light's PPA with Duke Energy's Happy Jack wind site, expiring September 3, 2028, provides up to 30 MW of wind energy from Happy Jack to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 50% of the facility output to Black Hills Power. |
• | Cheyenne Light's PPA with Duke Energy's Silver Sage wind site, expiring September 30, 2029, for up to 30 MW of wind energy. Under a separate intercompany agreement, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to Black Hills Power. |
• | Colorado Electric's PPA with PSCo expiring December 31, 2012, whereby Colorado Electric purchases 50 MW of economy energy. |
• | Colorado Electric's PPA with Cargill expiring December 31, 2013, whereby Colorado Electric purchases 50 MW of economy energy. |
2011 | 2010 | 2009 | |||||||
PPA with PacifiCorp | $ | 12,515 | $ | 12,936 | $ | 11,862 | |||
PPA with PSCo (a) | $ | 97,988 | $ | 110,575 | $ | 97,899 | |||
Transmission services agreement with PacifiCorp | $ | 1,215 | $ | 1,215 | $ | 1,215 | |||
PPA with Happy Jack | $ | 1,955 | $ | 2,815 | $ | 2,078 | |||
PPA with Silver Sage | $ | 3,281 | $ | 1,723 | $ | 713 |
(a) | This PPA with PSCo expired on December 31, 2011 and was replaced with the facilities constructed by Colorado Electric at our Pueblo Airport Generation site and the facilities constructed by Black Hills Colorado IPP to support a new PPA with Colorado Electric. |
2012 | $ | 199,811 | |
2013 | $ | 123,600 | |
2014 | $ | 73,145 | |
2015 | $ | 70,140 | |
2016 | $ | 46,568 | |
Thereafter | $ | 202,779 |
• | During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU; |
• | During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves; |
• | Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light provides 40 MW of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 MW of capacity and energy from Basin Electric through March 13, 2013. The agreements became effective March 14, 2011; |
• | Black Hills Power has a PPA with MEAN expiring April 1, 2015. Under this contract, MEAN purchases 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III; and |
• | Black Hills Power has a PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III is based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement. |
2011 | 2010 | 2009 | |||||||
Depreciation expense on capitalized asset retirement costs | $ | 5,212 | $ | 6,519 | $ | 1,993 |
Maximum Exposure at | ||||
Nature of Guarantee | December 31, 2011 | Year Expiring | ||
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings (1) | $ | 70,000 | Ongoing | |
Guarantees for payment obligations arising from purchase contracts for four gas turbines for Black Hills Colorado IPP (2) | 384 | 2012 | ||
Guarantees for payment obligations arising from purchase contracts for two gas turbines for Colorado Electric (3) | 56 | 2012 | ||
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric (4) | 33,264 | January 15, 2013 | ||
Indemnification for subsidiary reclamation/surety bonds (5) | 18,601 | Ongoing | ||
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Black Hills Utility Holdings (6) | 10,000 | July 31, 2012 | ||
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply (7) | 7,500 | June 30, 2012 | ||
$ | 139,805 |
(1) | We have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related physical and financial transactions with BP Energy Company and/or BP Canada Energy Marketing Corp, Northern Natural Gas Company and PSCo. These commodity transactions secure natural gas supply for our regulated gas utilities. The guarantee is a continuing guarantee that may be terminated upon 30 days written notice to the counterparty. |
(2) | We have issued four guarantees to GE for payment obligations arising from contracts to purchase four LM6000 gas turbines for Black Hills Colorado IPP. These are continuous guarantees which will terminate upon settlement of all obligations. |
(3) | We have issued two guarantees to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers. These are continuing guarantees which will terminate upon settlement of all obligations. |
(4) | We have issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric relating to the purchase of wind turbines for the Colorado Electric wind power generation project. This guarantee will remain in effect until satisfaction of Colorado Electric's contractual obligations. |
(5) | We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets. |
(6) | We issued a guarantee to Colorado Interstate Gas Company for payment obligations of Black Hills Utility Holdings related to natural gas transportation, storage and services agreements. |
(7) | We issued a guarantee to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchase. |
2011 | 2010 | 2009 | |||||||
Acquisition of properties: | |||||||||
Proved | $ | 673 | $ | — | $ | — | |||
Unproved | 8,317 | 3,846 | 3,443 | ||||||
Exploration costs | 44,384 | 8,159 | 5,962 | ||||||
Development costs | 38,638 | 25,264 | 10,133 | ||||||
Asset retirement obligations incurred | 43 | 1,228 | 623 | ||||||
Total costs incurred | $ | 92,055 | $ | 38,497 | $ | 20,161 |
2011 | 2010 | 2009 | ||||||||||||||||
Oil | Gas | Oil | Gas | Oil | Gas | |||||||||||||
(in Mbbls of oil and MMcf of gas) | ||||||||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||||
Balance at beginning of year | 5,940 | 95,456 | 5,274 | 87,660 | 5,185 | 154,432 | ||||||||||||
Production (a) | (452 | ) | (8,526 | ) | (376 | ) | (8,484 | ) | (366 | ) | (9,710 | ) | ||||||
Additions - acquisitions (sales) | (84 | ) | — | (13 | ) | (377 | ) | — | — | |||||||||
Additions - extensions and discoveries | 927 | 29,664 | 1,145 | 1,710 | 152 | 2,560 | ||||||||||||
Revisions to previous estimates (b) | (108 | ) | (20,690 | ) | (90 | ) | 14,947 | 303 | (59,622 | ) | ||||||||
Balance at end of year | 6,223 | 95,904 | 5,940 | 95,456 | 5,274 | 87,660 | ||||||||||||
Proved developed reserves at end of year included above | 4,830 | 71,867 | 4,434 | 67,656 | 4,274 | 74,911 | ||||||||||||
Proved undeveloped reserves at the end of year included in above | 1,393 | 24,037 | 1,506 | 27,800 | 1,000 | 12,749 | ||||||||||||
NYMEX prices | $ | 96.19 | $ | 4.12 | $ | 79.43 | $ | 4.38 | $ | 61.18 | $ | 3.87 | ||||||
Well-head reserve prices | $ | 88.49 | $ | 3.59 | $ | 70.82 | $ | 3.45 | $ | 53.59 | $ | 2.52 |
(a) | Production for reserve calculations does not include volumes for natural gas liquids (NGL's). |
(b) | Included in the total revisions are (23.6) Bcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2.3 Bcfe in various basins. Revisions due to cost and commodity pricing were less than 1% Bcfe. |
• | Companies are required to include a narrative disclosure of the total quantity of PUDs at year end, any material changes in PUDs during the year, and investment and progress made in converting the PUDs during the year. In 2011, we invested approximately $18.9 million to drill and develop 9 PUD locations from our 2010 inventory totaling approximately 4.7 Bcfe in proved developed reserve recognition. 100% of the PUD development in 2011 was in the Williston Basin which resulted in approximately 13 additional PUDs (4.6 net Bcfe) added to our year-end 2011 reserves. Additional PUDs were added in the Piceance (3 gross locations, 12.0 net Bcfe) and San Juan (2 gross locations, 7.5 net Bcfe) basins following 2011 drilling in those basins. |
• | Approximately 23.6 Bcfe were dropped from the proved reserves in 2011 due to five year aging of the PUDs. This drop was primarily in the Piceance (21.2 Bcfe, 17 gross locations, $34.7 million future investment), Bear Paw Uplift (0.5 Bcfe, 17 gross locations, $0.8 million future investment), and Wind River Basin (2.0 Bcfe, 25 gross locations, and $3.6 million future investment). |
• | As of December 31, 2011, PUD locations, proved reserves and future development costs associated with certain locations are as follows: |
As of December 31, 2011 | |||||||
Basin | Proved Reserves (in Bcfe) | Gross PUD Locations | Future Development Costs (in millions) | ||||
Piceance | 12.8 | 4 | $ | 26.7 | |||
Williston | 10.5 | 33 | 46.3 | ||||
Bear Paw Uplift | 1.0 | 32 | 2.0 | ||||
San Juan | 8.1 | 3 | 15.1 | ||||
32.4 | 72 | $ | 90.1 |
• | None of our PUD locations have been reflected in our reserves for five or more years. Consistent with the SEC guidance, these PUD locations will be monitored and reported each year until they are drilled or revised. |
2011 | 2010 | 2009 | |||||||
Unproved oil and gas properties | $ | 28,656 | $ | 28,160 | $ | 29,351 | |||
Proved oil and gas properties | 674,494 | 592,978 | 582,276 | ||||||
Gross capitalized costs | 703,150 | 621,138 | 611,627 | ||||||
Accumulated depreciation, depletion and amortization and valuation allowances | (361,173 | ) | (334,955 | ) | (335,605 | ) | |||
Net capitalized costs | $ | 341,977 | $ | 286,183 | $ | 276,022 |
2011 | 2010 | 2009 | |||||||
Revenue | $ | 79,808 | $ | 74,164 | $ | 70,684 | |||
Production costs | 23,820 | 21,922 | 21,653 | ||||||
Depreciation, depletion and amortization and valuation provisions* | 34,415 | 29,013 | 72,338 | ||||||
Total costs | 58,235 | 50,935 | 93,991 | ||||||
Results of operations from producing activities before tax | 21,573 | 23,229 | (23,307 | ) | |||||
Income tax benefit (expense) | (7,442 | ) | (8,014 | ) | 8,041 | ||||
Results of operations from producing activities (excluding general and administrative costs and interest costs) | $ | 14,131 | $ | 15,215 | $ | (15,266 | ) |
* | Includes pre-tax ceiling test impairment charges of $43.3 million in 2009. |
2011 | 2010 | 2009 | Prior | Total | |||||||||||
Leasehold acquisition cost | $ | 3,451 | $ | 3,442 | $ | 887 | $ | 17,119 | $ | 24,899 | |||||
Exploration cost | 16,745 | — | — | — | 16,745 | ||||||||||
Capitalized interest | 291 | 404 | 55 | 3,006 | 3,756 | ||||||||||
Total | $ | 20,487 | $ | 3,846 | $ | 942 | $ | 20,125 | $ | 45,400 |
2011 | 2010 | 2009 | |||||||
Future cash inflows | $ | 931,637 | $ | 764,585 | $ | 519,867 | |||
Future production costs | (280,910 | ) | (256,455 | ) | (207,783 | ) | |||
Future development costs | (92,233 | ) | (73,805 | ) | (34,961 | ) | |||
Future income tax expense | (157,922 | ) | (111,666 | ) | (51,287 | ) | |||
Future net cash flows | 400,572 | 322,659 | 225,836 | ||||||
10% annual discount for estimated timing of cash flows | (197,215 | ) | (154,551 | ) | (96,728 | ) | |||
Standardized measure of discounted future net cash flows | $ | 203,357 | $ | 168,108 | $ | 129,108 |
2011 | 2010 | 2009 | |||||||
Standardized measure - beginning of year | $ | 168,108 | $ | 129,108 | $ | 179,226 | |||
Sales and transfers of oil and gas produced, net of production costs | (52,914 | ) | (40,282 | ) | (26,836 | ) | |||
Net changes in prices and production costs | 57,087 | 57,380 | (40,786 | ) | |||||
Extensions, discoveries and improved recovery, less related costs | 31,179 | 17,076 | 3,324 | ||||||
Changes in future development costs | 43,809 | (17,125 | ) | 83,000 | |||||
Development costs incurred during the period | 18,940 | 4,975 | 4,620 | ||||||
Revisions of previous quantity estimates | (58,211 | ) | 27,513 | (104,556 | ) | ||||
Accretion of discount | 19,655 | 13,434 | 19,596 | ||||||
Net change in income taxes | (23,283 | ) | (23,233 | ) | 11,520 | ||||
Purchases of reserves | — | — | — | ||||||
Sales of reserves | (1,013 | ) | (738 | ) | — | ||||
Standardized measure - end of year | $ | 203,357 | $ | 168,108 | $ | 129,108 |
For the Years Ended | |||||||||
December 31, 2011 | December 31, 2010 | December 31, 2009 | |||||||
Revenue | $ | 41,101 | $ | 27,999 | $ | 13,381 | |||
Pre-tax income from discontinued operations | 14,838 | 8,673 | 1,950 | ||||||
Income tax (expense) benefit | (5,473 | ) | (3,129 | ) | (464 | ) | |||
Income from discontinued operations | $ | 9,365 | $ | 5,544 | $ | 1,486 |
Years Ended | |||||||||
Business Segment | December 31, 2011 | December 31, 2010 | December 31, 2009 | ||||||
Electric Utilities | $ | 1,613 | $ | 1,650 | $ | 1,666 | |||
Gas Utilities | 1,043 | 1,092 | 1,177 | ||||||
Oil and Gas | 407 | 435 | 538 | ||||||
Power Generation | 228 | 233 | 231 | ||||||
Coal Mining | 127 | 105 | 141 | ||||||
$ | 3,418 | $ | 3,515 | $ | 3,753 |
As of | ||||||
December 31, 2011 | December 31, 2010 | |||||
Other current assets | $ | 280,221 | $ | 257,082 | ||
Derivative assets, current and non-current | 52,859 | 50,498 | ||||
Property, plant and equipment, net | 5,828 | 3,699 | ||||
Goodwill | 1,435 | 1,435 | ||||
Other non-current assets | 508 | 1,521 | ||||
Other current liabilities | (132,951 | ) | (152,602 | ) | ||
Derivative liabilities, current and non-current | (26,084 | ) | (18,014 | ) | ||
Other non-current liabilities | (14,894 | ) | (2,707 | ) | ||
Net assets | $ | 166,922 | $ | 140,912 |
December 31, 2011 | ||||||||||||||||||
Level 1 | Level 2 | Level 3 | Counterparty Netting | Cash Collateral | Total | |||||||||||||
Assets: | ||||||||||||||||||
Commodity derivatives - Energy Marketing | $ | — | $ | 789,537 | $ | 6,139 | $ | (743,154 | ) | $ | 337 | $ | 52,859 | |||||
Liabilities: | ||||||||||||||||||
Commodity derivatives - Energy Marketing | $ | — | $ | 771,534 | $ | 5,411 | $ | (743,154 | ) | $ | (7,707 | ) | $ | 26,084 |
December 31, 2010 | ||||||||||||||||||
Level 1 | Level 2 | Level 3 | Counterparty Netting | Cash Collateral | Total | |||||||||||||
Assets: | ||||||||||||||||||
Commodity derivatives - Energy Marketing | $ | — | $ | 166,405 | $ | 7,976 | $ | (122,639 | ) | $ | (1,410 | ) | $ | 50,332 | ||||
Foreign currency | — | 166 | — | — | — | 166 | ||||||||||||
Total | $ | — | $ | 166,571 | $ | 7,976 | $ | (122,639 | ) | $ | (1,410 | ) | $ | 50,498 | ||||
Liabilities: | ||||||||||||||||||
Commodity derivatives - Energy Marketing | $ | — | $ | 143,537 | $ | 2,463 | $ | (122,639 | ) | $ | (5,368 | ) | $ | 17,993 | ||||
Foreign currency | — | 21 | — | — | — | 21 | ||||||||||||
Total | $ | — | $ | 143,558 | $ | 2,463 | $ | (122,639 | ) | $ | (5,368 | ) | $ | 18,014 |
Commodity Derivatives | Commodity Derivatives | |||||
December 31, 2011 | December 31, 2010 | |||||
Balance at beginning of year | $ | 5,513 | $ | (937 | ) | |
Unrealized losses | (8,631 | ) | (2,525 | ) | ||
Unrealized gains | 6,094 | 7,295 | ||||
Settlements | (2,248 | ) | (1,179 | ) | ||
Transfers in to level 3(a) | — | 1,457 | ||||
Transfers out of level 3(b) | — | 1,402 | ||||
Balance at year end | $ | 728 | $ | 5,513 | ||
Changes in unrealized (losses) gains relating to instruments still held as of year end | $ | (825 | ) | $ | 1,078 |
December 31, 2011 | December 31, 2010 | ||||||||||||
Balance Sheet Location | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | |||||||||
Derivatives designated as hedges: | |||||||||||||
Commodity derivatives | Assets of discontinued operations | $ | — | $ | — | $ | 10,952 | $ | 1,452 | ||||
Commodity derivatives | Assets of discontinued operations | — | — | 48 | 71 | ||||||||
Commodity derivatives | Liabilities of discontinued operations | 5,256 | 403 | — | 45 | ||||||||
Commodity derivatives | Liabilities of discontinued operations | — | — | — | — | ||||||||
$ | 5,256 | $ | 403 | $ | 11,000 | $ | 1,568 | ||||||
Derivatives not designated as hedges: | |||||||||||||
Commodity derivatives | Assets of discontinued operations | $ | 55,413 | $ | 13,740 | $ | 142,013 | $ | 107,795 | ||||
Commodity derivatives | Assets of discontinued operations | 76,629 | 54,784 | 9,757 | 3,099 | ||||||||
Commodity derivatives | Liabilities of discontinued operations | 691,453 | 729,309 | 20,588 | 39,051 | ||||||||
Commodity derivatives | Liabilities of discontinued operations | 4,852 | 9,354 | 978 | 4,442 | ||||||||
Foreign currency | Assets of discontinued operations | — | — | 166 | 21 | ||||||||
$ | 828,347 | $ | 807,187 | $ | 173,502 | $ | 154,408 |
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||
(in thousands, except per share amounts, dividends and common stock prices) | ||||||||||||
2011 | ||||||||||||
Revenue | $ | 400,835 | $ | 260,649 | $ | 249,523 | $ | 361,181 | ||||
Operating income | 58,367 | 36,160 | 39,572 | 52,140 | ||||||||
Income (loss) from continuing operations (a) | 29,068 | 3,706 | (11,163 | ) | 18,754 | |||||||
Income (loss) from discontinued operations | (2,158 | ) | 4,046 | 638 | 6,839 | |||||||
Net income (loss) available for common stock (a) | 26,910 | 7,752 | (10,525 | ) | 25,593 | |||||||
Income (loss) per share for continuing operations - basic | $ | 0.74 | $ | 0.09 | $ | (0.29 | ) | $ | 0.45 | |||
Income (loss) per share for discontinued operations - basic | (0.05 | ) | 0.11 | 0.02 | 0.16 | |||||||
Income (loss) per share - basic | $ | 0.69 | $ | 0.20 | $ | (0.27 | ) | $ | 0.61 | |||
Income (loss) per share for continuing operations - diluted | $ | 0.73 | $ | 0.09 | $ | (0.29 | ) | $ | 0.44 | |||
Income (loss) per share for discontinued operations - diluted | (0.05 | ) | 0.10 | 0.02 | 0.16 | |||||||
Income (loss) per share - diluted | $ | 0.68 | $ | 0.19 | $ | (0.27 | ) | $ | 0.60 | |||
Dividends paid per share | $ | 0.365 | $ | 0.365 | $ | 0.365 | $ | 0.365 | ||||
Common stock prices - High | $ | 33.64 | $ | 34.85 | $ | 32.22 | $ | 34.47 | ||||
Common stock prices - Low | $ | 29.76 | $ | 28.12 | $ | 25.83 | $ | 29.10 |
(a) | Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million, and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively. |
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||
(in thousands, except per share amounts, dividends and common stock prices) | ||||||||||||
2010 | ||||||||||||
Revenue (a) | $ | 416,728 | $ | 247,443 | $ | 240,521 | $ | 314,999 | ||||
Operating income (b) | $ | 64,698 | $ | 27,170 | $ | 44,695 | $ | 46,857 | ||||
Income (loss) from continuing operations (b) (c) | $ | 28,705 | $ | (10,688 | ) | $ | 10,493 | $ | 34,631 | |||
Income (loss) from discontinued operations | $ | 2,729 | $ | 2,029 | $ | 1,897 | $ | (1,111 | ) | |||
Net income (loss) available for common stock (b) (c) | $ | 31,434 | $ | (8,659 | ) | $ | 12,390 | $ | 33,520 | |||
Income (loss) per share, Basic: | ||||||||||||
Earnings (loss) per share for continuing operations | $ | 0.74 | $ | (0.27 | ) | $ | 0.27 | $ | 0.89 | |||
Earnings (loss) per share for discontinued operations | 0.07 | 0.05 | 0.05 | (0.03 | ) | |||||||
Earnings (loss) per share - basic | $ | 0.81 | $ | (0.22 | ) | $ | 0.32 | $ | 0.86 | |||
Income (loss) per share, Diluted: | ||||||||||||
Earnings (loss) per share for continuing operations | $ | 0.74 | $ | (0.27 | ) | $ | 0.27 | $ | 0.88 | |||
Earnings (loss) per share for discontinued operations | 0.07 | 0.05 | 0.05 | (0.03 | ) | |||||||
Earnings (loss) per share - diluted | $ | 0.81 | $ | (0.22 | ) | $ | 0.32 | $ | 0.85 | |||
Dividends paid per share | $ | 0.36 | $ | 0.36 | $ | 0.36 | $ | 0.36 | ||||
Common stock prices - High | $ | 30.83 | $ | 34.49 | $ | 33.31 | $ | 33.42 | ||||
Common stock prices - Low | $ | 25.65 | $ | 27.34 | $ | 27.79 | $ | 29.32 |
(a) | Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated. See Note 1. |
(b) | Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively. |
(c) | Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 million after-tax in the first, second, third and fourth quarters, respectively. |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
ITEM 9A. | CONTROLS AND PROCEDURES |
• | The assessment of the impact of certain non-routine transactions on the accuracy of our year-end income tax provision was not effective. |
• | Tax resources were not sufficient to effectively prepare and review the analysis of tax accounts. |
• | Communication between the tax department and the Controller organization was not effective to ensure income tax accounting consequences were adequately considered. |
• | Increase tax department resources to ensure completion and documentation of a more thorough analysis that supports our calculation of the effective tax rate and valuation of deferred tax assets and liabilities. |
• | Implement formal periodic meetings among the Chief Financial Officer, Controller and the tax department to ensure adequate consideration of items that may impact income tax accounting. |
ITEM 9B. | OTHER INFORMATION |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
ITEM 11. | EXECUTIVE COMPENSATION |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Equity Compensation Plan Information | |||||||||||
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||||
(a) | (b) | (c) | |||||||||
Equity compensation plans approved by security holders | 437,665 | (1) | $ | 30.50 | (1) | 961,476 | (2) | ||||
Equity compensation plans not approved by security holders | — | $ | — | — | |||||||
Total | 437,665 | $ | 30.50 | 961,476 |
(1) | Includes 173,989 full value awards outstanding as of December 31, 2011, comprised of restricted stock units, performance shares and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares or common stock units. In addition, 278,155 shares of unvested restricted stock were outstanding as of December 31, 2011, which are not included in the above table because they have already been issued. |
(2) | Shares available for issuance are from the 2005 Omnibus Incentive Plan. The 2005 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards. |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a) | 1. | Consolidated Financial Statements |
Financial statements required under this item are included in Item 8 of Part II | ||
2. | Schedules | |
Schedule I — Condensed Financial Information of the Registrant | ||
Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2011, 2010 and 2009 | ||
All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto. |
Years ended December 31, | 2011 | 2010 | 2009 | ||||||
(in thousands) | |||||||||
Revenue | $ | — | $ | — | $ | — | |||
Operating expenses | 772 | 735 | 524 | ||||||
Operating income (loss) | (772 | ) | (735 | ) | (524 | ) | |||
Other income (expense): | |||||||||
Equity income (loss) in earnings of subsidiaries | 87,150 | 88,627 | 57,394 | ||||||
Interest expense | (15,229 | ) | (14,985 | ) | (17,786 | ) | |||
Unrealized (loss) gain on interest rate swaps, net | (42,010 | ) | (15,193 | ) | 55,653 | ||||
Interest income | 3 | 22 | 10 | ||||||
Other income (expense), net | (42 | ) | 34 | 28 | |||||
Total other income (expense) | 29,872 | 58,505 | 95,299 | ||||||
Income (loss) from continuing operations before income taxes | 29,100 | 57,770 | 94,775 | ||||||
Income tax benefit (expense) | 20,630 | 10,915 | (13,025 | ) | |||||
Income (loss) from continuing operations | 49,730 | 68,685 | 81,750 | ||||||
Loss from discontinued operations | — | — | (195 | ) | |||||
Net income (loss) available for common stock | $ | 49,730 | $ | 68,685 | $ | 81,555 |
At December 31, | 2011 | 2010 | ||||
(in thousands) | ||||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 3,114 | $ | 219 | ||
Accounts receivable — affiliates, current | 1,445 | 869 | ||||
Notes receivable — affiliates, current | 453,216 | 201,497 | ||||
Deferred income tax assets, net, current | 36,951 | 21,137 | ||||
Other current assets | 15,831 | 15,173 | ||||
Total current assets | 510,557 | 238,895 | ||||
Property and Equipment | 1,135 | — | ||||
Investments in subsidiaries | 1,339,024 | 1,269,123 | ||||
Notes receivable — affiliate, non-current | 575,000 | 575,000 | ||||
Deferred income tax assets, net, non-current | 29,454 | 44,587 | ||||
Other long-term assets | 4,834 | 3,889 | ||||
Total other assets, non-current | 609,288 | 623,476 | ||||
TOTAL ASSETS | $ | 2,460,004 | $ | 2,131,494 | ||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable -- affiliate, current | $ | 5,202 | $ | 1,613 | ||
Derivative liabilities, current | 78,502 | 57,343 | ||||
Notes payable | 345,000 | 249,000 | ||||
Notes payable — affiliate, current | 1,754 | 25,232 | ||||
Other current liabilities | 12,070 | 12,109 | ||||
Total current liabilities | 442,528 | 345,297 | ||||
Derivative liabilities, non-current | 31,368 | 7,360 | ||||
Long-term debt | 774,959 | 674,930 | ||||
Note payable — affiliate, non-current | 1,813 | 3,637 | ||||
Total long-term debt | 776,772 | 678,567 | ||||
Total stockholders' equity | 1,209,336 | 1,100,270 | ||||
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ | 2,460,004 | $ | 2,131,494 |
Years ended December 31, | 2011 | 2010 | 2009 | ||||||
(in thousands) | |||||||||
Operating activities: | |||||||||
Net income (loss) | $ | 49,730 | $ | 68,685 | $ | 81,555 | |||
Loss from discontinued operations, net of tax | — | — | 195 | ||||||
Income from continuing operations | 49,730 | 68,685 | 81,750 | ||||||
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities — | |||||||||
Equity in earnings of subsidiaries | (87,150 | ) | (88,627 | ) | (57,394 | ) | |||
Dividend from subsidiaries | 14,500 | 6,298 | — | ||||||
Stock compensation | 5,643 | 5,637 | 3,908 | ||||||
Unrealized mark-to-market (gain) loss on certain interest rate swaps | 42,010 | 15,193 | (55,653 | ) | |||||
Derivative fair value adjustments | 2,291 | (6,384 | ) | 1,461 | |||||
Deferred income taxes | 2,599 | (34,452 | ) | 19,224 | |||||
Other adjustments | 4,376 | 2,508 | (254 | ) | |||||
Change in operating assets and liabilities — | |||||||||
Accounts receivable and other current assets | (5,141 | ) | 2,198 | 41,237 | |||||
Accounts payable and other current liabilities | 3,550 | 4,846 | (22,906 | ) | |||||
Other operating activities | 550 | (2,514 | ) | 1,399 | |||||
Net cash provided by (used in) operating activities of continuing operations | 32,958 | (26,612 | ) | 12,772 | |||||
Net cash used by operating activities of discontinued operations | — | — | (195 | ) | |||||
Net cash provided by (used in) operating activities | 32,958 | (26,612 | ) | 12,577 | |||||
Investing activities: | |||||||||
Property, plant and equipment additions | (1,135 | ) | — | — | |||||
Increase in advances to affiliate | (258,117 | ) | (216,337 | ) | (115,731 | ) | |||
Other investing activities | — | — | — | ||||||
Net cash provided by (used in) investing activities | (259,252 | ) | (216,337 | ) | (115,731 | ) | |||
Financing activities: | |||||||||
Dividends paid on common stock | (59,202 | ) | (56,467 | ) | (55,151 | ) | |||
Common stock issued | 123,041 | 3,246 | 4,819 | ||||||
Decrease in short-term borrowings | (821,300 | ) | (770,000 | ) | (742,500 | ) | |||
Increase in short-term borrowings | 1,017,300 | 854,500 | 631,075 | ||||||
Notes payable to affiliate | (25,302 | ) | 14,995 | — | |||||
Long-term debt — issuance | — | 200,000 | 248,500 | ||||||
Other financing activities | (5,348 | ) | (5,379 | ) | 1,500 | ||||
Net cash provided by financing activities | 229,189 | 240,895 | 88,243 | ||||||
Net change in cash and cash equivalents | 2,895 | (2,054 | ) | (14,911 | ) | ||||
Cash and cash equivalents beginning of year | 219 | 2,273 | 17,184 | ||||||
Cash and cash equivalents end of year | $ | 3,114 | $ | 219 | $ | 2,273 |
Supplemental Cash Flow Information | |||||||||
Years ended December 31, | 2011 | 2010 | 2009 | ||||||
(in thousands) | |||||||||
Non-cash investing and financing activities- | |||||||||
Non-cash adjustment to notes receivable from affiliate | $ | — | $ | 62,019 | $ | 66,034 | |||
Non-cash adjustment to notes payable to affiliate | $ | — | $ | 13,874 | $ | — | |||
Non-cash dividend from affiliates | $ | — | $ | — | $ | 225,000 | |||
Cash (paid) refunded during the period for- | |||||||||
Interest | $ | (14,667 | ) | $ | (56,464 | ) | $ | (19,878 | ) |
Income taxes | $ | 23,830 | $ | (504 | ) | $ | 6,667 |
2011 | 2010 | 2009 | |||||||
Cash Dividends paid to Parent by subsidiaries | $ | 14,500 | $ | 6,298 | $ | — | |||
Non-Cash Dividends paid to Parent by subsidiaries | $ | — | $ | — | $ | 225,000 |
Due Date | Interest Rate | 2011 | 2010 | ||||||
Senior unsecured notes due 2013 (a) | May 15, 2013 | 6.50 | % | $ | 225,000 | $ | 225,000 | ||
Unamortized discount on notes due 2013 | (41 | ) | (70 | ) | |||||
Senior unsecured notes due 2014 (a) | May 15, 2014 | 9.00 | % | 250,000 | 250,000 | ||||
Senior unsecured notes due 2020 (b) | July 15, 2020 | 5.88 | % | 200,000 | 200,000 | ||||
Long-term term loan | September 30, 2013 | 1.69 | % | 100,000 | — | ||||
Total senior unsecured notes | $ | 774,959 | $ | 674,930 |
(a) | In order to restructure debt and equity capitalization at our utilities, this senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent's Condensed Balance Sheets. |
(b) | In order to restructure debt and equity capitalization at our utilities, $100.0 million of this senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent's Condensed Balance Sheets. |
Maximum Exposure at | |||||
Nature of Guarantee | December 31, 2011 | Year Expiring | |||
Guarantees for payment obligations arising from commodity-related physical and financial transactions by Black Hills Utility Holdings | $ | 70,000 | Ongoing | ||
Guarantees for payment obligations arising from purchase contracts for four gas turbines for Black Hills Colorado IPP | 384 | 2012 | |||
Guarantees for payment obligations arising from purchase contracts for two gas turbines for Colorado Electric | 56 | 2012 | |||
Guarantees for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric | 33,264 | 2013 | |||
Indemnification for subsidiary reclamation/surety bonds | 18,601 | Ongoing | |||
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Black Hills Utility Holdings | 10,000 | July 31, 2012 | |||
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply | 7,500 | June 30, 2012 | |||
$ | 139,805 |
December 31, 2011 | December 31, 2010 | |||||||||||
Interest Rate Swaps | De-designated Interest Rate Swaps | Interest Rate Swaps | De-designated Interest Rate Swaps | |||||||||
Notional * | $ | 75,000 | $ | 250,000 | $ | 75,000 | $ | 250,000 | ||||
Weighted average fixed interest rate | 4.97 | % | 5.67 | % | 4.97 | % | 5.67 | % | ||||
Maximum terms in years | 5.0 | 2.0 | 6.0 | 1.0 | ||||||||
Current derivative assets | $ | — | $ | — | $ | — | $ | — | ||||
Non-current derivative assets | $ | — | $ | — | $ | — | $ | — | ||||
Current derivative liabilities | $ | 3,207 | $ | 75,295 | $ | 3,363 | $ | 53,980 | ||||
Non-current derivative liabilities | $ | 10,672 | $ | 20,696 | $ | 7,360 | $ | — | ||||
Pre-tax accumulated other comprehensive (loss) | $ | (13,879 | ) | $ | — | $ | (15,417 | ) | $ | — | ||
Pre-tax gain (loss) | $ | — | $ | (42,010 | ) | $ | — | $ | (15,193 | ) | ||
Cash collateral receivable (payable) included in Consolidated Balance Sheets | $ | — | $ | — | $ | — | $ | — |
* | Under the terms of the Black Hills Wyoming project financing, Black Hill Wyoming was required to become a party to hedging agreements fixing the interest rate on a portion of the principal amount of the debt. To accomplish this, two existing swap agreements were amended so that the Parent and Black Hills Wyoming are now both jointly and severally liable for the full amount of the obligations under the swap agreements. As of January 15, 2010, the mark to market liability associated with the two swaps with a notional value of $75.0 million was transferred from the Parent to Black Hills Wyoming. The balance in AOCI of the Parent was frozen at that point in time and is being amortized over the remaining life of the swaps through the quarterly settlement process. |
Liabilities: | Level 1 | Level 2 | Level 3 | Total | ||||||||
December 31, 2011 | ||||||||||||
Interest rate swaps | $ | — | $ | 109,869 | $ | — | $ | 109,869 | ||||
December 31, 2010 | ||||||||||||
Interest rate swaps | $ | — | $ | 64,703 | $ | — | $ | 64,703 |
December 31, 2011 | December 31, 2010 | ||||||
Balance Sheet Location | Fair Value of Liability Derivative | ||||||
Derivatives designated as hedges: | |||||||
Interest rate swaps | Derivative liability - current | $ | 3,207 | $ | 3,363 | ||
Interest rate swaps | Derivative liability - non-current | 10,672 | 7,360 | ||||
$ | 13,879 | $ | 10,723 | ||||
Derivatives not designated as hedges: | |||||||
Interest rate swaps | Derivative liability - current | $ | 75,295 | $ | 53,980 | ||
Interest rate swaps | Derivative liability - non-current | $ | 20,696 | $ | — | ||
$ | 95,991 | $ | 53,980 |
Derivatives in Cash Flow Hedging Relationships | Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | Location of Gain/ (Loss) Reclassified from AOCI into Income (Effective Portion) | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | ||||
December 31, 2011 | |||||||
Interest rate swaps | $ | (3,893 | ) | Interest expense | $ | (3,950 | ) |
December 31, 2010 | |||||||
Interest rate swaps | $ | (5,352 | ) | Interest expense | $ | (3,662 | ) |
December 31, 2011 | December 31, 2010 | December 31, 2009 | ||||||||
Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | ||||||
Interest rate swaps - unrealized | Unrealized gain (loss) on interest rate swap | $ | (42,010 | ) | $ | (15,193 | ) | $ | 55,653 | |
Interest rate swaps - realized | Interest expense | (13,373 | ) | (13,312 | ) | (9,816 | ) | |||
$ | (55,383 | ) | $ | (28,505 | ) | $ | 45,837 |
2011 | 2010 | ||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||
Cash | $ | 3,114 | $ | 3,114 | $ | 219 | $ | 219 | |||||
Derivative financial instruments - liabilities | $ | 109,870 | $ | 109,870 | $ | 64,703 | $ | 64,703 | |||||
Notes payable | $ | 345,000 | $ | 345,000 | $ | 249,000 | $ | 249,000 | |||||
Long-term debt | $ | 774,959 | $ | 851,241 | $ | 674,930 | $ | 743,738 |
BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009 | ||||||||||||||||||||||||
Description | Balance at Beginning of Year | Adjustments | Additions Charged to Costs and Expenses | Recoveries and Other Additions | Write-offs and Other Deductions | Balance at End of Year | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Allowance for doubtful accounts: | ||||||||||||||||||||||||
2011 | $ | 2,295 | $ | — | $ | 3,042 | $ | 5,369 | $ | (9,045 | ) | $ | 1,661 | |||||||||||
2010 | $ | 3,683 | $ | — | $ | 1,898 | $ | 2,196 | $ | (5,482 | ) | $ | 2,295 | |||||||||||
2009 | $ | 3,916 | $ | — | $ | 4,078 | $ | 3,229 | $ | (7,540 | ) | $ | 3,683 |
3. | Exhibits |
Exhibit Number | Description |
3.1* | Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant's Form 10-K for 2004). |
3.2* | Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant's Form 8-K filed on February 3, 2010). |
4.1* | Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant's Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant's Form 8-K filed on July 15, 2010). |
4.2* | Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant's Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 (No. 333-150669)). |
4.3* | Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant's Form 10-K for 2000). |
10.1*† | Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant's Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant's Form 10-K for 2002). Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant's Form 10-K for 2008). |
10.2*† | 2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant's Form 10-K for 2008). |
10.3*† | Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant's Form 10-K for 2008). First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2011). |
10.4*† | Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011. |
10.5*† | Black Hills Corporation 2005 Omnibus Incentive Plan ("Omnibus Plan") (filed as Appendix A to the Registrant's Proxy Statement filed April 13, 2005). First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2008). Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant's Form 8-K filed on May 26, 2010). |
10.6*† | Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.13 to the Registrant's Form 10-K for 2008). |
10.7*† | Form of Restricted Stock Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.15 to the Registrant's Form 10-K for 2008). |
10.8*† | Form of Restricted Stock Unit Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.17 to the Registrant's Form 10-K for 2008). |
10.9*† | Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2010 (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2009). |
10.10† | Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2012. |
10.11*† | Form of Short-term Incentive for Omnibus Plan effective for awards granted on or after January 1, 2010. (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarterly period ended March 31, 2010). |
10.12*† | Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant's Form 8-K filed on September 3, 2004). |
10.13*† | Change in Control Agreement dated September 7, 2010 between Black Hills Corporation and David R. Emery (filed as Exhibit 10.1 to the Registrant's Form 8-K filed on September 10, 2010). |
10.14*† | Form of Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant's Form 8-K filed on September 10, 2010). |
10.15*† | Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant's Form 10-K for 2008). First Amendment to the Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant's Form 10-K for 2010). |
10.16*† | Independent Contractor Agreement dated May 3, 2010, between Black Hills Corporation and Lone Mountain Investment, Inc. (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2010). First Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated July 27, 2011 (filed as Exhibit 10.3 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2011). |
10.17† | Second Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated December 12, 2011. |
10.18†* | Consulting Services Agreement between Black Hills Corporation, Thomas M. Ohlmacher and T.O.P., LLC dated December 1, 2010 (filed as Exhibit 10 to the Registrant's Form 8-K filed on December 2, 2010). |
10.19† | Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees. |
10.20* | Credit Agreement dated December 15, 2010 among Black Hills Corporation as Borrower, the financial institutions party thereto, as Banks, JPMorgan Chase Bank N.A., as Administrative Agent, and JPMorgan Securities LLC and Union Bank of California N.A., as Co-Lead Arrangers and Joint Book Runner (filed as Exhibit 10 to the Registrant's Form 8-K filed on December 16, 2010). First Amendment to the Credit Agreement (filed as Exhibit 10 to the Registrant's Form 8-K filed on October 3, 2011). |
10.21* | Credit Agreement, dated February 1, 2012, among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other banks party thereto (filed as Exhibit 10 to the Registrant's Form 8-K filed on February 3, 2012). |
10.22* | Credit Agreement, dated as June 24, 2011, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, The Bank of Nova Scotia, as Administrative Agent, Co-Lead Arranger and Joint Book Runner, and U.S. Bank N.A. and CoBank, ACB, as Co-Lead Arrangers and Joint Book Runners (filed as Exhibit 10 to the Registrant's Form 8-K filed on June 29, 2011). |
10.23* | Third Amended and Restated Credit Agreement, effective May 8, 2009, among Enserco Energy Inc., as borrower, Fortis Capital Corp., as administrative agent, collateral agent, co-lead arranger and co-Bookrunner, Societe Generale, as co-lead arranger, co-bookrunner and syndication Agent, BNP Paribas, as co-lead arranger, co-bookrunner and documentation agent, U.S. Bank National Association, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and the other financial institutions which may become parties thereto (“Enserco Credit Agreement”) (filed as Exhibit 10.1 to the Registrant's Form 8-K filed October 20, 2009). Joinder Agreements, dated May 27, 2009, to the Enserco Credit Agreement (filed as Exhibits 10.1, 10.2 and 10.3 to the Registrant's Form 8-K filed on May 28, 2009). First Amendment to the Enserco Credit Agreement effective August 25, 2009 (filed as Exhibit 10 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2009). Second Amendment to the Enserco Credit Agreement effective December 30, 2009 (filed as Exhibit 10.19 to the Registrant's Form 10-K for 2009). Third Amendment to the Enserco Credit Agreement effective May 7, 2010 (filed as Exhibit 10 to the Registrant's Form 8-K filed May 13, 2010). Joinder Agreement dated May 28, 2010 to the Enserco Credit Agreement (filed as Exhibit 10.1 to the Registrant's Form 8-K filed on June 3, 2010). Fourth Amendment to the Enserco Credit Agreement effective May 28, 2010 (filed as Exhibit 10.2 to the Registrant's Form 8-K filed June 3, 2010). Fifth Amendment to the Enserco Credit Agreement effective July 12, 2010 (filed as Exhibit 10 to the Registrant's Form 8-K filed on July 13, 2010). Sixth Amendment to the Enserco Credit Agreement effective September 21, 2010 (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2010). Seventh Amendment to the Enserco Credit Agreement effective May 12, 2011 (filed as Exhibit 10.4 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2011). |
10.24* | Coal Leases between WRDC and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant's Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant's Form 10‑K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant's Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant's Form 10‑K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant's Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant's Form 10‑K for 1989). |
10.25* | Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1997). |
21 | List of Subsidiaries of Black Hills Corporation. |
23.1 | Independent Auditors' Consent. |
23.2 | Consent of Petroleum Engineer and Geologist. |
31.1 | Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. |
31.2 | Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. |
32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
95 | Mine Safety and Health Administration Safety Data |
99 | Report of Cawley, Gillespie & Associates, Inc. |
101 | Financial Statements in XBRL Format |
* | Previously filed as part of the filing indicated and incorporated by reference herein. |
† | Indicates a board of director or management compensatory plan. |
(a) | See (a) 3. Exhibits above. |
(b) | See (a) 2. Schedules above. |
BLACK HILLS CORPORATION | |||
By: | /S/ DAVID R. EMERY | ||
David R. Emery, Chairman, President | |||
and Chief Executive Officer | |||
Dated: | February 29, 2012 |
/S/ DAVID R. EMERY | Director and | February 29, 2012 |
David R. Emery, Chairman, President | Principal Executive Officer | |
and Chief Executive Officer | ||
/S/ ANTHONY S. CLEBERG | Principal Financial and | February 29, 2012 |
Anthony S. Cleberg, Executive Vice President | Accounting Officer | |
and Chief Financial Officer | ||
/S/ DAVID C. EBERTZ | Director | February 29, 2012 |
David C. Ebertz | ||
/S/ JACK W. EUGSTER | Director | February 29, 2012 |
Jack W. Eugster | ||
/S/ JOHN R. HOWARD | Director | February 29, 2012 |
John R. Howard | ||
/S/ STEVEN R. MILLS | Director | February 29, 2012 |
Steven R. Mills | ||
/S/ STEPHEN D. NEWLIN | Director | February 29, 2012 |
Stephen D. Newlin | ||
/S/ GARY L. PECHOTA | Director | February 29, 2012 |
Gary L. Pechota | ||
/S/ REBECCA B. ROBERTS | Director | February 29, 2012 |
Rebecca B. Roberts | ||
/S/ WARREN L. ROBINSON | Director | February 29, 2012 |
Warren L. Robinson | ||
/S/ JOHN B. VERING | Director | February 29, 2012 |
John B. Vering | ||
/S/ THOMAS J. ZELLER | Director | February 29, 2012 |
Thomas J. Zeller |
Exhibit Number | Description |
3.1* | Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant's Form 10-K for 2004). |
3.2* | Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant's Form 8-K filed on February 3, 2010). |
4.1* | Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant's Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to the Registrant's Form 8-K filed on July 15, 2010). |
4.2* | Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant's Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 (No. 333-150669)). |
4.3* | Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant's Form 10-K for 2000). |
10.1*† | Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant's Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant's Form 10-K for 2002). Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant's Form 10-K for 2008). |
10.2*† | 2005 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.3 to the Registrant's Form 10-K for 2008). |
10.3*† | Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant's Form 10-K for 2008). First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2011). |
10.4*† | Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011. |
10.5*† | Black Hills Corporation 2005 Omnibus Incentive Plan ("Omnibus Plan") (filed as Appendix A to the Registrant's Proxy Statement filed April 13, 2005). First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2008). Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant's Form 8-K filed on May 26, 2010). |
10.6*† | Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.13 to the Registrant's Form 10-K for 2008). |
10.7*† | Form of Restricted Stock Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.15 to the Registrant's Form 10-K for 2008). |
10.8*† | Form of Restricted Stock Unit Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2009 (filed as Exhibit 10.17 to the Registrant's Form 10-K for 2008). |
10.9*† | Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2010 (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2009). |
10.10† | Form of Performance Share Award Agreement for Omnibus Plan effective for awards granted on or after January 1, 2012. |
10.11*† | Form of Short-Term Incentive for Omnibus Plan effective for awards granted on or after January 1, 2010. (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarterly period ended March 31, 2010). |
10.12*† | Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant's Form 8-K filed on September 3, 2004). |
10.13*† | Change in Control Agreement dated September 7, 2010 between Black Hills Corporation and David R. Emery (filed as Exhibit 10.1 to the Registrant's Form 8-K filed on September 10, 2010). |
10.14*† | Form of Change in Control Agreements between Black Hills Corporation and its non-CEO Senior Executive Officers (filed as Exhibit 10.2 to the Registrant's Form 8-K filed on September 10, 2010). |
10.15*† | Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant's Form 10-K for 2008). First Amendment to the Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant's Form 10-K for 2010). |
10.16*† | Independent Contractor Agreement dated May 3, 2010, between Black Hills Corporation and Lone Mountain Investment, Inc. (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2010). First Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated July 27, 2011 (filed as Exhibit 10.3 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2011). |
10.17† | Second Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated December 12, 2011. |
10.18†* | Consulting Services Agreement between Black Hills Corporation, Thomas M. Ohlmacher, and T.O.P. LLC dated December 1, 2010 (filed as Exhibit 10 to the Registrant's Form 8-K filed on December 2, 2010). |
10.19† | Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees. |
10.20* | Credit Agreement dated December 15, 2010 among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, JPMorgan Chase Bank N.A., as Administrative Agent, and JP Morgan Securities LLC and Union Bank of California, N.A., as Co-Lead Arrangers and Joint Book Runners (filed as Exhibit 10 to the Registrant's Form 8-K filed on December 16, 2010). First Amendment to the Credit Agreement (filed as Exhibit 10 to the Registrant's Form 8-K filed on October 3, 2011). |
10.21* | Credit Agreement, dated February 1, 2012, among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other banks party thereto (filed as Exhibit 10 to the Registrant's Form 8-K filed on February 3, 2012). |
10.22* | Credit Agreement, dated as June 24, 2011, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, The Bank of Nova Scotia, as Administrative Agent, Co-Lead Arranger and Joint Book Runner, and U.S. Bank N.A. and CoBank, ACB, as Co-Lead Arrangers and Joint Book Runners (filed as Exhibit 10 to the Registrant's Form 8-K filed on June 29, 2011). |
10.23* | Third Amended and Restated Credit Agreement effective May 8, 2009, among Enserco Energy Inc., as borrower, Fortis Capital Corp., as administrative agent and collateral agent, Societe Generale as Syndication Agent, BNP Paribas as documentation agent, U.S. Bank National Association, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and the other financial institutions which may become parties thereto ("Enserco Credit Agreement") (filed as Exhibit 10.1 to the Registrant's Form 8-K filed October 20, 2009). Joinder Agreements dated May 27, 2009 to the Enserco Credit Agreement (filed as Exhibits 10.1, 10.2 and 10.3 to the Registrant's Form 8-K filed on May 28, 2009). First Amendment to the Enserco Credit Agreement effective August 25, 2009 (filed as Exhibit 10 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2009). Second Amendment to the Enserco Credit Agreement effective December 30, 2009 (filed as Exhibit 10.19 to the Registrant's Form 10-K for 2009). Third Amendment to the Enserco Credit Agreement effective May 7, 2010 (filed as Exhibit 10 to the Registrant's Form 8-K filed May 13, 2010). Joinder Agreement dated May 28, 2010 to the Enserco Credit Agreement (filed as Exhibit 10.1 to the Registrant's Form 8-K filed on June 3, 2010). Fourth Amendment to the Enserco Credit Agreement effective May 28, 2010 (filed as Exhibit 10.2 to the Registrant's Form 8-K filed June 3, 2010). Fifth Amendment to the Enserco Credit Agreement effective July 12, 2010 (filed as Exhibit 10 to the Registrant's Form 8-K filed on July 13, 2010). Sixth Amendment to the Enserco Credit Agreement effective September 21, 2010 (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2010). Seventh Amendment to the Enserco Credit Agreement effective May 12, 2011 (filed as Exhibit 10.4 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2011). |
10.24* | Coal Leases between WRDC and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant's Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant's Form 10‑K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant's Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant's Form 10‑K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant's Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant's Form 10‑K for 1989). |
10.25* | Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1997). |
21 | List of Subsidiaries of Black Hills Corporation. |
23.1 | Independent Auditors' Consent. |
23.2 | Consent of Petroleum Engineer and Geologist. |
31.1 | Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. |
31.2 | Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. |
32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
95 | Mine Safety and Health Administration Safety Data |
99 | Report of Cawley, Gillespie & Associates, Inc. |
101 | Financial Statements in XBRL Format |
* | Previously filed as part of the filing indicated and incorporated by reference herein. |
† | Indicates a board of director or management compensatory plan. |
Article 1. Performance Period | 2 |
Article 2. Value of Performance Shares | 2 |
Article 3. Performance Shares and Achievement of Performance Measure | 2 |
Article 4. Termination Provisions | 3 |
Article 5. Change in Control | 3 |
Article 6. Forfeiture and Repayment | 5 |
Article 7. Dividends | 8 |
Article 8. Form and Timing of Payment of Performance Shares | 8 |
Article 9. Nontransferability | 8 |
Article 10.Administration | 8 |
Article 11.Miscellaneous | 9 |
Alliant Energy Corp | LNT | NV Energy, Inc. | NVE |
ALLETE Inc. | ALE | OGE Energy Corp | OGE |
Avista Corp | AVA | Piedmont Natural Gas | PNY |
CH Energy Group Inc. | CHG | PNM Resources, Inc. | PNM |
Cleco Corp | CNL | Portland General Electric Co. | POR |
GenOn Energy Inc. | GEN | Questar Corp | STR |
Great Plains Energy Inc. | GXP | Southwest Gas Corp | SWX |
IDACORP Inc. | IDA | UIL Holdings Corp | UIL |
MDU Resources Group Inc. | MDU | UniSource Energy Corp | UNS |
National Fuel Gas Co. | NFG | Vectren Corp | VVC |
NorthWestern Corp | NWE | Westar Energy Inc. | WR |
(a) | The number of Performance Shares to be earned under this Agreement shall be based upon the achievement of pre-established TSR performance goals as set by the Compensation Committee of the Board of Directors (the “Committee”) for the Performance Period, based on the following chart: |
TSR Performance Relative to Companies in Peer Index | Payout (% of Target) |
85th Percentile or Above | 200.00% |
80th Percentile | 175.00% |
70th Percentile | 150.00% |
60th Percentile | 125.00% |
50th Percentile | 100.00% |
40th Percentile | 75.00% |
30th Percentile | 50.00% |
Below the 30th Percentile | —% |
Total Shareholder Return | = | Change in Stock Price + Dividends Paid Beginning Stock Price |
(a) | The acquisition in a transaction or series of transactions by any Person of Beneficial Ownership of thirty percent (30%) or more of the combined voting power of the then outstanding shares of common stock of the Company; provided, however, that for purposes of this Agreement, the following acquisitions will not constitute a Change in Control: (A) any acquisition by the Company; (B) any acquisition of common stock of the Company by an underwriter holding securities of the Company in connection with a public offering thereof; and (C) any acquisition by any Person pursuant to a transaction which complies with subsections (c) (i), (ii) and (iii), below; |
(b) | Individuals who, as of December 31, 2009 are members of the Board (the "Incumbent Board"), cease for any reason to constitute at least a majority of the members of the Board; provided, however, that if the election, or nomination for election by the Company's common shareholders, of any new director was approved by a vote of at least two-thirds of the Incumbent Board, such new director shall, for purposes of this Plan, be considered as a member of the Incumbent Board; provided further, however, that no individual shall be considered a member of the Incumbent Board if such individual initially assumed office as a result of either an actual or threatened "Election Contest" (as described in Rule 14a‑11 promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board (a "Proxy Contest") including by reason of any agreement intended to avoid or settle any Election Contest or Proxy Contest; |
(c) | Consummation, following shareholder approval, of a reorganization, merger, or consolidation of the Company and/or its subsidiaries, or a sale or other disposition (whether by sale, taxable or non-taxable exchange, formation of a joint venture or otherwise) of fifty percent (50%) or more of the assets of the Company and/or its subsidiaries (each a “Business Combination”), unless, in each case, immediately following such Business Combination, (i) all or substantially all of the individuals and entities who were beneficial owners of shares of the common stock of the Company immediately prior to such Business Combination beneficially own, directly or indirectly, more that fifty percent (50%) of the combined voting power of the then outstanding shares of the entity resulting from the Business Combination or any direct or indirect parent corporation thereof (including, without limitation, an entity which as a result of such transaction owns the Company or all or substantially all of the |
(d) | Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company, except pursuant to a Business Combination that complies with subsections (c) (i), (ii), and (iii) above. |
(e) | A Change in Control shall not be deemed to occur solely because any Person (the "Subject Person") acquired Beneficial Ownership of more than the permitted amount of the then outstanding Common Stock as a result of the acquisition of Common Stock by the Company which, by reducing the number of shares of Common Stock then outstanding, increases the proportional number of shares Beneficially Owned by the Subject Persons, provided that if a Change in Control would occur (but for the operation of this sentence) as a result of the acquisition of Common Stock by the Company, and after such stock acquisition by the Company, the Subject Person becomes the Beneficial Owner of any additional Common Stock which increases the percentage of the then outstanding Common Stock Beneficially Owned by the Subject Person, then a Change in Control shall occur. |
(f) | A Change in Control shall not be deemed to occur unless and until all regulatory approvals required in order to effectuate a Change in Control of the Company have been obtained and the transaction constituting the Change in Control has been consummated. |
(a) | In the event the Participant incurs a separation from service for a reason other than those described in Article 4 herein during the Performance Period this entire award will be forfeited, unless the separation from service follows a Change in Control. |
(b) | Without limiting the generality of Article 6(a), the Company reserves the right to cancel all Performance Shares awarded hereunder, whether or not vested, and require the Participant to repay all income or gains previously realized in respect of such Performance Shares, in the event of the occurrence of any of the following events: |
(i) | termination of Participant’s employment for Cause; |
(ii) | within one year following any termination of Participant’s employment, the Board determines that the Participant engaged in conduct before the Participant’s termination date that would have constituted the basis for a termination of employment for Cause; |
(iii) | at any time during the Participant’s employment or the twelve month period immediately following any termination of employment, Participant: |
(x) | publicly disparages the Company, any of its affiliates or any of its or their officers, directors or senior executive employees or otherwise makes any public statement that is materially detrimental to the interests or reputation of the Company, any of its affiliates or such individuals; or |
(y) | violates in any material respect any policy or any code of ethics or standard of behavior or conduct generally applicable to Participant, including the Code of Conduct; or |
(iv) | Participant engages in any fraudulent, illegal or other misconduct involving the Company or any of its affiliates, including but not limited to any breach of fiduciary duty, breach of a duty of loyalty, or interference with contract or business expectancy. |
(c) | If the Board determines that the Participant’s conduct, activities or circumstances constitute events described in Article 6(b), in addition to any other remedies the Company has available to it, the Company may in its sole discretion: |
(i) | cancel any Performance Shares awarded hereby, whether or not issued; and/or |
(ii) | require the Participant to repay an amount equal to all income or gain realized in respect of all such Performance Shares. The amount of repayment shall include, without limitation, amounts received in connection with the delivery or sale of Shares of such Performance Shares or cash paid in respect of any Performance Shares. |
(d) | The Board, in its discretion, shall determine whether a Participant’s conduct, activities or circumstances constitute events described in Article 6(b) and whether and to what extent the Performance Shares awarded hereby shall be forfeited by Participant and/or a Participant shall be required to repay an amount pursuant to Article 6(c). The Board shall have the authority to suspend the payment, delivery or settlement of all or any portion of such Participant’s outstanding Performance Shares pending an investigation of a bona fide dispute regarding Participant’s eligibility to receive a payment under the terms of this Agreement as determined by the Board in good faith. |
(e) | For purposes of applying this provision: |
(i) | “Cause” means any of the following: |
(u) | a Participant’s violation of his or her material duties to the Company or any of its affiliates, which continues after written notice from the Company or any affiliate to cure such violation; |
(v) | Participant’s willful failure to follow the lawful written directives of the Board in any material respect; |
(w) | Participant’s willful misconduct in connection with the performance of any of his or her duties, including but not limited to falsifying or attempting to falsify documents, books or records of the Company or any of its affiliates, making or delivering a false representation, statement or certification of compliance to the Company, misappropriating or attempting to misappropriate funds or other property of the Company or any of its affiliates, or securing or attempting to secure any personal profit in connection with any transaction entered into on behalf of the Company or any of its affiliates; |
(x) | Participant’s breach of any material provisions of this Agreement or any other non-competition, non-interference, non-disclosure, confidentiality or other similar agreement executed by Participant with the Company or any of its affiliates; |
(y) | conviction (or plea of nolo contendere) of the Participant of any felony, or a misdemeanor involving false statement, in connection with conduct involving the Company or any of its subsidiaries or affiliates; or |
(z) | intentional engagement in any activity which would constitute or cause a breach of duty of loyalty, or any fiduciary duty to the Company or any of its subsidiaries or affiliates. |
(ii) | “Code of Conduct” means any code of ethics or code of conduct now or hereafter adopted by the Company or any of its affiliates, including to the extent applicable the Company’s Employee Conduct and Disclosure Policy, as amended or supplemented from time to time, and the Company’s or subsidiary Risk Management Policies and Procedures, as amended, supplemented or replaced from time to time. |
(f) | Participant agrees that the provisions of this Article 6 are entered into in consideration of, and as a material inducement to, the agreements by the Company herein as well as an inducement for the Company to enter into this Agreement, and that, but for Participant’s agreement to the provisions of this Article 6, the Company would not have entered into this Agreement. |
(a) | The Participant shall have no right with respect to any Award or a portion there of, until such award shall be paid to such Participant. |
(b) | If the Committee determines, in its sole discretion, that a Participant at any time has willfully engaged in any activity that the Committee determines was or is harmful to the Company, any unpaid pending Award will be forfeited by such Participant. |
(c) | All appropriate taxes will be withheld from the cash portion of the award. |
(a) | The selection of any employee for participation in the Plan shall not give such Participant any right to be retained in the employ of the Company. The right and power of the Company to dismiss or discharge any Participant at-will, is specifically reserved. Such Participant or any person claiming under or through the Participant shall not have any right or interest in the Plan or any Award thereunder, unless and until all terms, conditions, and provisions of the Plan that affect such Participant have been complied with as specified herein. |
(b) | With the approval of the Board, the Committee may terminate, amend, or modify the Plan; provided, however, that no such termination, amendment, or modification of the Plan may in any way adversely affect the Participant’s rights under this Agreement without the Participant’s written consent, except as required by law. |
(c) | Participant shall not have voting rights with respect to the Performance Shares. Participant shall obtain voting rights upon the settlement of Performance Shares and distribution into shares of common stock of the Company. |
(d) | The Participant may defer such Participant’s receipt of the payment of cash and the delivery of shares of common stock, that would otherwise be due to such Participant by virtue of the satisfaction of the performance goals with respect to the Performance Shares, pursuant to the rules of the Black Hills Corporation Nonqualified Deferred Compensation Plan and the procedures set forth by the Compensation Committee. If the Participant elects to defer the receipt of the award, the Participant will be required to pay any necessary taxes from their own funds. They will not be allowed to have their deferred award reduced for tax withholding. |
(e) | This Agreement shall be subject to all applicable laws, rules, and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required. |
(f) | To the extent not preempted by federal law, this Agreement shall be governed by, and construed in accordance with, the laws of the State of South Dakota. |
(g) | Any awards received by Participant are subject to the provisions of the Stock Ownership Guidelines approved by the Board of Directors. |
(h) | Waiver and Modification. The provisions of this Agreement may not be waived or modified unless such waiver or modification is in writing and signed by the Company. |
(i) | Compliance with Exchange Act. If the Participant is subject to Section 16 of the Exchange Act, Performance Shares granted pursuant to the Award are intended to comply with all applicable conditions of Rule 16b-3 or its successors under the Exchange Act. |
1. | The term of the Agreement as stated in Article 3 (Agreement Expiration) is extended in order to permit the performance of Services up to or until January 31, 2012. In the event that Services are satisfactorily completed prior to that date, this Agreement may be terminated pursuant to the provisions of Article 4. |
2. | This Amendment to the Agreement sets forth the only alterations intended by the parties and constitutes their entire understanding and agreement. Subject to the terms of this Amendment, the Agreement remains in full force and effect and the terms thereof may not be waived, altered or further modified without the written agreement of the parties. |
Subsidiary Name | State of Origin | BHC's Ownership | Description of Subsidiary's Authorized Capital Stock, if not wholly owned | |
1. | Black Hills Cabresto Pipeline, LLC | Delaware | 100% | N/A |
2. | Black Hills/Colorado Electric Utility Company, LP | Delaware | 100% | N/A |
3. | Black Hills/Colorado Gas Utility Company, LP | Delaware | 100% | N/A |
4. | Black Hills/Colorado Utility Company, LLC | Colorado | 100% | N/A |
5. | Black Hills/Colorado Utility Company II, LLC | Colorado | 100% | N/A |
6. | Black Hills Colorado IPP, LLC | South Dakota | 100% | N/A |
7. | Black Hills Electric Generation, LLC | South Dakota | 100% | N/A |
8. | Black Hills Exploration and Production, Inc. | Wyoming | 100% | N/A |
9. | Black Hills Gas Resources, Inc. | Colorado | 100% | N/A |
10. | Black Hills Gas Holdings Corp. | Colorado | 100% | N/A |
11. | Black Hills/Iowa Gas Utility Company, LLC | Delaware | 100% | N/A |
12. | Black Hills/Kansas Gas Utility Company, LLC | Kansas | 100% | N/A |
13. | Black Hills Midstream, LLC | South Dakota | 100% | N/A |
14. | Black Hills/Nebraska Gas Utility Company, LLC | Delaware | 100% | N/A |
15. | Black Hills Non-regulated Holdings, LLC | South Dakota | 100% | N/A |
16. | Black Hills Plateau Production, LLC | Delaware | 100% | N/A |
17. | Black Hills Power, Inc. | South Dakota | 100% | N/A |
18. | Black Hills Service Company, LLC | South Dakota | 100% | N/A |
19. | Black Hills Utility Holdings, Inc. | South Dakota | 100% | N/A |
20. | Black Hills Wyoming, LLC | Wyoming | 100% | N/A |
21. | Buick Power, LLC | Delaware | 50% | BHC indirectly owns 50% of the outstanding Membership Units |
22. | Cheyenne Light, Fuel and Power Company | Wyoming | 100% | N/A |
23. | EIF Investors, Inc. | Delaware | 100% | N/A |
24. | Enserco Energy Inc. | South Dakota | 100% | N/A |
25. | Enserco Midstream, LLC | South Dakota | 100% | N/A |
26. | Generation Development Company, LLC | South Dakota | 100% | N/A |
27. | Mallon Oil Company, Sucursal Costa Rica | Costa Rica | 100% | N/A |
28. | Natural/Peoples Limited Liability Company | Wyoming | 50% | BHC indirectly owns 50% of the outstanding Membership Units |
29. | Wyodak Resources Development Corp. | Delaware | 100% | N/A |
CAWLEY, GILLESPIE & ASSOCIATES, INC. | |
/S/ J. ZANE MEEKINS | |
J. Zane Meekins | |
Senior Vice President | |
Fort Worth, Texas | |
February 28, 2012 |
1. | I have reviewed this Annual Report on Form 10-K of Black Hills Corporation; | |
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(s) 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 (the 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. | |
5. | The registrant’s other certifying officer(s) 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 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 control 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: | February 29, 2012 | ||
/S/ DAVID R. EMERY | |||
David R. Emery | |||
Chairman, President and | |||
Chief Executive Officer |
1. | I have reviewed this Annual Report on Form 10-K of Black Hills Corporation; | |
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(s) 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 (the 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. | |
5. | The registrant’s other certifying officer(s) 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 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 control 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: | February 29, 2012 | ||
/S/ ANTHONY S. CLEBERG | |||
Anthony S. Cleberg | |||
Executive Vice President and | |||
Chief Financial Officer |
(1) | The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; 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: | February 29, 2012 | ||
/S/ DAVID R. EMERY | |||
David R. Emery | |||
Chairman, President and | |||
Chief Executive Officer |
(1) | The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; 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: | February 29, 2012 | ||
/S/ ANTHONY S. CLEBERG | |||
Anthony S. Cleberg | |||
Executive Vice President and | |||
Chief Financial Officer |
• | Total number of violations of mandatory health and safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA; |
• | Total number of orders issued under section 104(b) of the Mine Act; |
• | Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health and safety standards under section 104(d) of the Mine Act; |
• | Total number of imminent danger orders issued under section 107(a) of the Mine Act; and |
• | Total dollar value of proposed assessments from MSHA under the Mine Act. |
Mine/ MSHA Identification Number | Mine Act Section 104 S&S Citations issued during 2011 | Mine Act Section 104(b) Orders (#) | Mine Act Section 104(d) Citations and Orders (#) | Mine Act Section 110(b)(2) Violations (#) | Mine Act Section 107(a) Imminent Danger Orders (#) | Total Dollar Value of Proposed MSHA Assessments ($ in thousands) | Total Number of Mining Related Fatalities (#) | Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no) | Legal Actions Pending as of Last Day of Period (#) * | Legal Actions Initiated During Period (#) | Legal Actions Resolved During Period (#) | |||||||||||
Wyodak Coal Mine - 4800083 | 1 | — | — | — | — | $ | 34.0 | — | No | 1 | 1 | 1 |
* | The types of proceedings by class: (1) contests of citations and orders - none; (2) contests of proposed penalties - one; (3) complaints for compensation - none; (4) complaints of discharge, discrimination or interference under Section 105 of the Mine Act - none; (5) applications for temporary relief - none; and (6) appeals of judges' decisions or orders to the FMSHRC - none. |
Proved | |||||||||
Proved | Developed | ||||||||
Developed | Non- | Proved | Total | ||||||
Producing | Producing | Undeveloped | Proved | ||||||
Net Reserves | |||||||||
Oil/Condensate | - Mbbl | 4,501.3 | 312.6 | 1,393.9 | 6,207.8 | ||||
Gas | - MMcf | 23,120.3 | 1,347.9 | 3,134.9 | 27,603.1 | ||||
Revenue | |||||||||
Oil/Condensate | - M$ | 403,724.6 | 27,114.3 | 118,555.1 | 549,393.9 | ||||
Gas | - M$ | 88,453.6 | 4,928.7 | 10,316.4 | 103,698.7 | ||||
Plant | - M$ | 36,784.5 | — | — | 36,784.5 | ||||
Severance and | |||||||||
Ad Valorem Taxes | - M$ | 53,541.7 | 3,624.3 | 14,225.3 | 71,391.3 | ||||
Operating Expenses | - M$ | 109,842.0 | 3,810.4 | 16,379.1 | 130,031.5 | ||||
Investments | - M$ | — | 1,032.7 | 48,236.6 | 49,269.3 | ||||
Operating Income (BFIT) | - M$ | 365,579.0 | 23,575.6 | 50,030.5 | 439,185.2 | ||||
Discounted at 10.0% | - M$ | 176,783.2 | 12,952.3 | 14,001.2 | 203,736.7 |
Proved | |||||||||
Proved | Developed | ||||||||
Developed | Non- | Proved | Total | ||||||
Producing | Producing | Undeveloped | Proved | ||||||
Net Reserves | |||||||||
Oil/Condensate | - Mbbl | 15.9 | — | — | 15.9 | ||||
Gas | - MMcf | 30,948.0 | 854.1 | 8,131.5 | 39,933.6 | ||||
Revenue | |||||||||
Oil/Condensate | - M$ | 1,315.7 | — | — | 1,315.7 | ||||
Gas | - M$ | 103,371.6 | 2,801.5 | 28,471.6 | 134,644.8 | ||||
Severance and | |||||||||
Ad Valorem Taxes | - M$ | 20,215.1 | 565.1 | 5,610.3 | 26,390.6 | ||||
Operating Expenses | - M$ | 25,118.1 | 719.1 | 3,230.9 | 29,068.0 | ||||
Investments | - M$ | — | 773.2 | 15,116.0 | 15,889.2 | ||||
Operating Income (BFIT) | - M$ | 59,354.1 | 744.2 | 4,514.4 | 64,612.7 | ||||
Discounted at 10.0% | - M$ | 35,673.1 | 352.6 | (3,775.1 | ) | 32,250.6 |
Proved | |||||||||
Proved | Developed | ||||||||
Developed | Non- | Proved | Total | ||||||
Producing | Producing | Undeveloped | Proved | ||||||
Net Reserves | |||||||||
Oil/Condensate | - Mbbl | — | — | — | — | ||||
Gas | - MMcf | 14,623.7 | 974.1 | 12,765.3 | 28,363.0 | ||||
Revenue | |||||||||
Oil/Condensate | - M$ | — | — | — | — | ||||
Gas | - M$ | 53,249.1 | 3,117.5 | 49,432.8 | 105,799.5 | ||||
Severance and | |||||||||
Ad Valorem Taxes | - M$ | 3,050.6 | 178.6 | 2,832.5 | 6,061.7 | ||||
Operating Expenses | - M$ | 13,204.5 | 660.2 | 4,102.4 | 17,967.1 | ||||
Investments | - M$ | — | 361.4 | 26,712.9 | 27,074.3 | ||||
Operating Income (BFIT) | - M$ | 36,994.1 | 1,917.2 | 15,785.1 | 54,696.4 | ||||
Discounted at 10.0% | - M$ | 20,540.3 | 779.1 | (2,220.3 | ) | 19,099.2 |
Property, Plant and Equipment Property, Plant and Equipment (Tables)
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Property, Plant and Equipment [Table Text Block] | Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
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Schedule I Disclosures for Parent Company Only Schedule I, Long Term Debt (Details) (Parent [Member], USD $)
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12 Months Ended | |||||||
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Dec. 31, 2011
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Dec. 31, 2010
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Debt Instrument [Line Items] | ||||||||
Related Party Transaction, Due from (to) Related Party | $ 100,000 | |||||||
Long-term Debt | 774,959,000 | 674,930,000 | ||||||
Senior Unsecured Notes due 2013 [Member]
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Debt Instrument [Line Items] | ||||||||
Long-term Debt, Maturity Date | May 15, 2013 | |||||||
Long-term Debt, Fixed Interest Rate | 6.50% | |||||||
Long-term Debt | 225,000,000 | [1] | 225,000,000 | [1] | ||||
Debt Instrument, Unamortized Discount | 41,000 | 70,000 | ||||||
Senior Unsecured Notes Due 2014 [Member]
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Debt Instrument [Line Items] | ||||||||
Long-term Debt, Maturity Date | May 15, 2014 | |||||||
Long-term Debt, Fixed Interest Rate | 9.00% | |||||||
Long-term Debt | 250,000,000 | [1] | 250,000,000 | [1] | ||||
Senior Unsecured Notes Due 2020 [Member]
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Debt Instrument [Line Items] | ||||||||
Long-term Debt, Maturity Date | Jul. 15, 2020 | |||||||
Long-term Debt, Fixed Interest Rate | 5.88% | |||||||
Long-term Debt | 200,000,000 | [2] | 200,000,000 | [2] | ||||
Proceeds from Issuance of Senior Long-term Debt | 198,700,000 | |||||||
Long Term Term Loan [Member]
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Debt Instrument [Line Items] | ||||||||
Long-term Debt, Maturity Date | Sep. 30, 2013 | |||||||
Long-term Debt, Variable Interest, Percentage Rate | 1.69% | |||||||
Long-term Debt | $ 100,000,000 | $ 0 | ||||||
Debt Instrument, Basis Spread on Variable Rate | 1.375% | |||||||
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Discontinued Operations Condensed Income Statement of Discontinued Operations (Tables)
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Dec. 31, 2011
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Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The following tables set forth, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):
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Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The following tables present the changes in level 3 recurring fair value (in thousands):
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Fair Value, by Balance Sheet Grouping [Table Text Block] | The estimated fair values of our financial instruments at December 31 were as follows (in thousands):
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Condensed Statement of Income [Member]
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Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block] | Operating results of the Energy Marketing segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands):
Total indirect corporate costs and inter-segment interest expenses previously allocated to Enserco were not reclassified to discontinued operations in accordance with GAAP and instead have been reclassified to our Corporate segment. An estimate of how these costs could have been allocated to segments other than Corporate is as follows (in thousands):
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Condensed Balance Sheet [Member]
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Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block] | Total assets and liabilities of Enserco have been classified as Current assets of discontinued operations and Current liabilities of discontinued operations on the accompanying Consolidated Balance Sheets at December 31, 2011 and 2010. Net assets of the Energy Marketing segment included in Discontinued operations were as follows (in thousands):
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Segment, Discontinued Operations [Member]
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Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] |
The following tables set forth, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis for our Energy Marketing Segment (in thousands):
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Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] |
The following tables set forth the roll forward of level 3 assets and liabilities that were accounted for at fair value on a recurring basis for our Energy Marketing Segment (in thousands):
(a) Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable. (b) Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the peri |
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Fair Value, by Balance Sheet Grouping [Table Text Block] | The following tables set forth, by the location of our assets and liabilities that were accounted for at fair value on a recurring basis for our Energy Marketing Segment (in thousands):
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Supplemental Cash Flow Information Supplemental Cash Flow Information (Tables)
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12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2011
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Supplemental Cash Flow Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Disclosure of Cash Flow Information |
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Guarantees Guarantees (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |||||||||||||||
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Dec. 31, 2011
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | $ 139,805 | |||||||||||||||
Parent [Member] | Electric Utilities [Member] | Capital Additions 180 MW Generation Facility Colorado Electric Utility [Member]
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 56 | [1] | ||||||||||||||
Guarantor Obligations, Term | 2012 | [1] | ||||||||||||||
Parent [Member] | Electric Utilities [Member] | Wind Turbines [Member]
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 33,264 | [2] | ||||||||||||||
Guarantor Obligations, Term | 1/15/2013 | [2] | ||||||||||||||
Parent [Member] | Coal [Member] | Surety Bonds [Member]
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 18,601 | [3] | ||||||||||||||
Guarantor Obligations, Term | Ongoing | [3] | ||||||||||||||
Parent [Member] | Power Generation [Member] | Capital Additions 200 MW Generation Facility Colorado IPP [Member]
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 384 | [4] | ||||||||||||||
Guarantor Obligations, Term | 2012 | [4] | ||||||||||||||
Parent [Member] | Gas Utilities [Member] | Natural Gas Storage and Transportation Supplier BP Energy [Member]
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 70,000 | [5] | ||||||||||||||
Guarantor Obligations, Term | Ongoing | [5] | ||||||||||||||
Parent [Member] | Gas Utilities [Member] | Natural Gas Transportation and Storage Supplier Colorado interstate [Member]
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 10,000 | [6] | ||||||||||||||
Guarantor Obligations, Term | 7/31/2012 | [6] | ||||||||||||||
Parent [Member] | Gas Utilities [Member] | Natural Gas Supplier Cross Timbers [Member]
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Guarantor Obligations [Line Items] | ||||||||||||||||
Guarantor Obligations, Maximum Exposure, Undiscounted | $ 7,500 | [7] | ||||||||||||||
Guarantor Obligations, Term | 6/30/2012 | [7] | ||||||||||||||
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Fair Value Measurements Fair Value Measurements Hedging Activities (Details) (USD $)
In Thousands, unless otherwise specified |
3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||||||||||
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Dec. 31, 2010
Cash Flow Hedging
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Dec. 31, 2011
Cash Flow Hedging
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Dec. 31, 2009
Cash Flow Hedging
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Dec. 31, 2010
Cash Flow Hedging
Commodity derivatives [Member]
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Dec. 31, 2011
Cash Flow Hedging
Commodity derivatives [Member]
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Dec. 31, 2009
Cash Flow Hedging
Commodity derivatives [Member]
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Dec. 31, 2010
Cash Flow Hedging
Commodity derivatives [Member]
Revenue
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Dec. 31, 2011
Cash Flow Hedging
Commodity derivatives [Member]
Revenue
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Dec. 31, 2009
Cash Flow Hedging
Commodity derivatives [Member]
Revenue
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Dec. 31, 2010
Cash Flow Hedging
Interest Rate Swap [Member]
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Dec. 31, 2011
Cash Flow Hedging
Interest Rate Swap [Member]
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Dec. 31, 2009
Cash Flow Hedging
Interest Rate Swap [Member]
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Dec. 31, 2010
Cash Flow Hedging
Interest Rate Swap [Member]
Interest Expense
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Dec. 31, 2011
Cash Flow Hedging
Interest Rate Swap [Member]
Interest Expense
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Dec. 31, 2009
Cash Flow Hedging
Interest Rate Swap [Member]
Interest Expense
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Dec. 31, 2011
Derivatives Not Designated as Hedge Instruments [Member]
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Dec. 31, 2010
Derivatives Not Designated as Hedge Instruments [Member]
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Dec. 31, 2009
Derivatives Not Designated as Hedge Instruments [Member]
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Dec. 31, 2011
Parent [Member]
Cash Flow Hedging
Interest Rate Swap [Member]
|
Dec. 31, 2010
Parent [Member]
Cash Flow Hedging
Interest Rate Swap [Member]
|
Dec. 31, 2011
Parent [Member]
Cash Flow Hedging
Interest Rate Swap [Member]
Interest Expense
|
Dec. 31, 2010
Parent [Member]
Cash Flow Hedging
Interest Rate Swap [Member]
Interest Expense
|
Dec. 31, 2011
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
|
Dec. 31, 2010
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
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Dec. 31, 2009
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
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Dec. 31, 2011
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
Interest Rate Swap [Member]
Unrealized Gain (Loss) on Interest Rate Swaps [Member]
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Dec. 31, 2010
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
Interest Rate Swap [Member]
Unrealized Gain (Loss) on Interest Rate Swaps [Member]
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Dec. 31, 2009
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
Interest Rate Swap [Member]
Unrealized Gain (Loss) on Interest Rate Swaps [Member]
|
Dec. 31, 2011
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
Interest Rate Swap [Member]
Interest Expense
|
Dec. 31, 2010
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
Interest Rate Swap [Member]
Interest Expense
|
Dec. 31, 2009
Parent [Member]
Derivatives Not Designated as Hedge Instruments [Member]
Interest Rate Swap [Member]
Interest Expense
|
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Derivative Instruments, Gain (Loss) | |||||||||||||||||||||||||||||||
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion) | $ 1,929 | $ (4,539) | $ (8,252) | $ 15,456 | $ 7,741 | $ (21,070) | $ (13,527) | $ (12,280) | $ 12,818 | $ (3,893) | $ (5,352) | ||||||||||||||||||||
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion) | 6,730 | (2,177) | 19,810 | 14,339 | 5,487 | 23,102 | (7,609) | (7,664) | (3,292) | (3,950) | (3,662) | ||||||||||||||||||||
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | 0 | 0 | (1,394) | 0 | 0 | (1,394) | 0 | 0 | 0 | ||||||||||||||||||||||
Amount of Gain/(Loss) on Derivatives Recognized in Income | $ (55,383) | $ (28,505) | $ 45,837 | $ (55,383) | $ (28,505) | $ 45,837 | $ (42,010) | $ (15,193) | $ 55,653 | $ (13,373) | $ (13,312) | $ (9,816) |
Oil and Gas Reserves (Unaudited) Proved Developed and Undeveloped Oil and Gas Reserve (Details) (Details)
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12 Months Ended | 12 Months Ended | ||||||||||||||||||||
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Dec. 31, 2011
Bcfe
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Dec. 31, 2010
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Dec. 31, 2009
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Mar. 31, 2009
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Dec. 31, 2011
Oil Reserves [Member]
MBbls
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Dec. 31, 2010
Oil Reserves [Member]
MBbls
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Dec. 31, 2009
Oil Reserves [Member]
MBbls
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Dec. 31, 2011
Natural Gas Reserves [Member]
MMcf
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Dec. 31, 2010
Natural Gas Reserves [Member]
MMcf
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Dec. 31, 2009
Natural Gas Reserves [Member]
MMcf
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Dec. 31, 2011
Oil and Gas Reserve Revisions, Five Year Aging Limit [Member]
Bcfe
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Dec. 31, 2011
Oil and Gas Reserve Revisions, Performance [Member]
Bcfe
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Proved Developed And Undevleoped Reserves [Roll Forward] | ||||||||||||||||||||||
Proved Developed and Undeveloped Reserves, Net | 5,940,000 | 5,274,000 | 5,185,000 | 95,456,000 | 87,660,000 | 154,432,000 | ||||||||||||||||
Proved Developed and Undeveloped Reserves, Production | (452,000) | [1] | (376,000) | [1] | (366,000) | [1] | (8,526,000) | [1] | (8,484,000) | [1] | (9,710,000) | [1] | ||||||||||
Proved Developed and Undeveloped Reserves, Additions, Acquisitions (Sales) | (84,000) | (13,000) | 0 | 0 | (377,000) | 0 | ||||||||||||||||
Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries | 35.2 | 927,000 | 1,145,000 | 152,000 | 29,664,000 | 1,710,000 | 2,560,000 | |||||||||||||||
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | (108,000) | [2] | (90,000) | 303,000 | (20,690,000) | [2] | 14,947,000 | (59,622,000) | (23.6) | 2.3 | ||||||||||||
Proved Developed and Undeveloped Reserves, Net | 6,223,000 | 5,940,000 | 5,274,000 | 95,904,000 | 95,456,000 | 87,660,000 | ||||||||||||||||
Crude Oil Price Per Barrel, Wellhead | 88.49 | 70.82 | 53.59 | 45.32 | ||||||||||||||||||
Crude Oil Price, per Barrel, NYMEX | 96.19 | 79.43 | 61.18 | 49.66 | ||||||||||||||||||
Natural Gas Price Per MCF, NYMEX | 4.12 | 4.38 | 3.87 | 3.63 | ||||||||||||||||||
Natural Gas Price Per MCF, Wellhead | 3.59 | 3.45 | 2.52 | 2.23 | ||||||||||||||||||
Proved Developed Reserves (Volume) | 4,830 | 4,434 | 4,274 | 71,867 | 67,656 | 74,911 | ||||||||||||||||
Proved Undeveloped Reserve (Volume) | 1,393 | 1,506 | 1,000 | 24,037 | 27,800 | 12,749 | ||||||||||||||||
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Quarterly Historical Data (Unaudited) Quarterly Historical Data (Unaudited) (Tables)
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Dec. 31, 2011
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Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Quarterly Financial Information [Table Text Block] | The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2011 and 2010.
__________________________
__________________________
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Notes Payable Notes Payable (Details) (USD $)
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12 Months Ended | 12 Months Ended | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
Dec. 31, 2008
|
Dec. 31, 2011
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
|
Dec. 31, 2010
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
|
Dec. 31, 2009
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
|
Dec. 31, 2011
Letters of Credit [Member]
Revolving Credit Facility, Existing [Member]
|
Dec. 31, 2011
Parent [Member]
|
Dec. 31, 2010
Parent [Member]
|
Dec. 31, 2011
Parent [Member]
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
|
Dec. 31, 2010
Parent [Member]
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
|
Dec. 31, 2011
Parent [Member]
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
Base Rate Option [Member]
|
Dec. 31, 2011
Parent [Member]
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
Eurodollar Option [Member]
|
Dec. 31, 2011
Parent [Member]
Line of Credit [Member]
Revolving Credit Facility, Existing [Member]
Letters of Credit [Member]
|
Dec. 31, 2011
Parent [Member]
Loans Payable [Member]
Corporate Term Loan due in 2011 [Member]
|
Dec. 31, 2010
Parent [Member]
Loans Payable [Member]
Corporate Term Loan due in 2011 [Member]
|
Dec. 31, 2011
Parent [Member]
Loans Payable [Member]
Corporate Term Loan due June 2012 [Member]
|
Dec. 31, 2010
Parent [Member]
Loans Payable [Member]
Corporate Term Loan due June 2012 [Member]
|
|
Line of Credit Facility | |||||||||||||||||||
Notes payable | $ 345,000,000 | $ 249,000,000 | $ 345,000,000 | $ 249,000,000 | $ 195,000,000 | $ 149,000,000 | $ 0 | $ 100,000,000 | $ 150,000,000 | $ 0 | |||||||||
Letters of Credit Outstanding, Amount | 43,700,000 | 46,865,000 | 43,700,000 | 46,865,000 | 0 | 0 | 0 | 0 | |||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 600,000,000 | ||||||||||||||||||
Line of Credit Facility, Expiration Date | 4/14/2013 | ||||||||||||||||||
Line of Credit Facility, Interest Rate at Period End | 1.75% | 2.75% | 2.75% | ||||||||||||||||
Line of Credit Facility, Commitment Fee Percentage | 0.50% | ||||||||||||||||||
Deferred Finance Costs Remaining, Noncurrent | 1,497,000 | ||||||||||||||||||
Amortization Expense for Deferred Financing Costs | 1,891,000 | 1,340,000 | 495,000 | ||||||||||||||||
Consolidated Net Worth, Actual | 1,209,336,000 | 1,100,270,000 | 1,084,837,000 | 1,050,536,000 | 1,209,336,000 | 1,209,336,000 | 1,100,270,000 | ||||||||||||
Line of Credit, Covenant Requirement, Consolidated Net Worth, Minimum | $ 884,131,000 | ||||||||||||||||||
Line of Credit Covenant Requirement, Recourse Leverage Ratio, Actual | 58.50% | ||||||||||||||||||
Line of Credit, Covenant Requirement, Recourse Leverage Ratio | 65.00% |
Business Segments Property, Plant and Equipment (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
||||
---|---|---|---|---|---|---|
Segment Reporting Information [Line Items] | ||||||
Property, plant and equipment, gross | $ 3,724,016 | $ 3,353,509 | ||||
Electric Utilities [Member]
|
||||||
Segment Reporting Information [Line Items] | ||||||
Property, plant and equipment, gross | 2,149,151 | [1] | 1,720,909 | [1] | ||
Gas Utilities [Member]
|
||||||
Segment Reporting Information [Line Items] | ||||||
Property, plant and equipment, gross | 523,374 | 502,360 | ||||
Oil and Gas [Member]
|
||||||
Segment Reporting Information [Line Items] | ||||||
Property, plant and equipment, gross | 763,645 | 680,407 | ||||
Power Generation [Member]
|
||||||
Segment Reporting Information [Line Items] | ||||||
Property, plant and equipment, gross | 135,981 | [1] | 297,907 | [1] | ||
Coal [Member]
|
||||||
Segment Reporting Information [Line Items] | ||||||
Property, plant and equipment, gross | 145,024 | 145,385 | ||||
Unallocated Amount to Segment [Member]
|
||||||
Segment Reporting Information [Line Items] | ||||||
Property, plant and equipment, gross | $ 6,841 | $ 6,541 | ||||
|
Income Taxes Income Taxes (Tables)
|
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2011
|
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Income Taxes [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
|
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Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31, were as follows (in thousands):
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reconciliation of Deferred Tax Liability to Deferred Tax Expense [Table Text Block] | The following table reconciles the change in the net deferred income tax liability from December 31, 2010 to December 31, 2011 to deferred income tax expense (in thousands):
|
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Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
_________________________
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Operating Loss Carryforwards [Table Text Block] | At December 31, 2011, we have federal and state NOL carryforwards of $534.8 million and $413.6 million, respectively, which will expire at various dates as follows (in thousands):
|
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Summary of Deferred Tax Liability Not Recognized [Table Text Block] | The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):
|
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Summary of Income Tax Contingencies [Table Text Block] |
|
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Interest Expense Income Included in Income Tax Expense Benefit [Table Text Block] | We recognized the following interest expense (benefit), included in Income tax (expense) benefit on the accompanying Consolidated Statements of Income, for the years ended December 31 as follows (in thousands):
|
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Summary of Other Tax Carryforwards [Table Text Block] | Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At December 31, 2011, we had the following remaining foreign tax credit carryforwards (in thousands):
|
Schedule II Consolidated Valuation and Qualifying Accounts
|
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2011
|
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Valuation and Qualifying Accounts Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Valuation and Qualifying Accounts Disclosure [Text Block] | SCHEDULE II
|
Notes Payable Notes Payable Corporate Term Loan (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |
---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Short-term Debt [Line Items] | ||
Notes payable | $ 345,000 | $ 249,000 |
Parent [Member]
|
||
Short-term Debt [Line Items] | ||
Notes payable | 345,000 | 249,000 |
Parent [Member] | Loans Payable [Member] | Corporate Term Loan due June 2012 [Member]
|
||
Short-term Debt [Line Items] | ||
Notes payable | $ 150,000 | $ 0 |
Long-term Debt, Maturity Date | Jun. 24, 2012 | |
Debt Instrument, Interest Rate Terms | 1.25% | |
Debt Instrument, Interest Rate at Period End | 1.56% |
Employee Benefit Plans Projected Benefit Plan Payments (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
---|---|
Pension Plans, Defined Benefit [Member]
|
|
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | $ 12,484 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 13,181 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 13,953 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 14,823 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 15,694 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 93,852 |
Supplemental Employee Retirement Plans, Defined Benefit [Member]
|
|
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 1,110 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 1,090 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 1,280 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 1,290 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 1,370 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 7,160 |
Other Postretirement Benefit Plans, Defined Benefit [Member]
|
|
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Defined Benefit Plan, Expected Future Benefit Payments in Year One | 4,250 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Two | 4,380 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Three | 4,320 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Four | 4,170 |
Defined Benefit Plan, Expected Future Benefit Payments in Year Five | 4,250 |
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | $ 21,950 |
Oil and Gas Reserves (Unaudited) Unproved Properties Excluded from Amortization (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
|
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Acquisition Costs, Period Cost | $ 24,899 | ||
Exploration Costs, Period Cost | 16,745 | ||
Capitalized Interest Of Cost Excluded From Amortization | 3,756 | ||
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost | 45,400 | ||
Current Year [Member]
|
|||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Acquisition Costs, Period Cost | 3,451 | ||
Exploration Costs, Period Cost | 16,745 | ||
Capitalized Interest Of Cost Excluded From Amortization | 291 | ||
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost | 20,487 | ||
Prior Year [Member]
|
|||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Acquisition Costs, Period Cost | 3,442 | ||
Exploration Costs, Period Cost | 0 | ||
Capitalized Interest Of Cost Excluded From Amortization | 404 | ||
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost | 3,846 | ||
More Than One Year, Less Than Two Years Prior [Member]
|
|||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Acquisition Costs, Period Cost | 887 | ||
Exploration Costs, Period Cost | 0 | ||
Capitalized Interest Of Cost Excluded From Amortization | 55 | ||
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost | 942 | ||
More Than Two Years Prior [Member]
|
|||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Acquisition Costs, Period Cost | 17,119 | ||
Exploration Costs, Period Cost | 0 | ||
Capitalized Interest Of Cost Excluded From Amortization | 3,006 | ||
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost | 20,125 | ||
Oil and Gas [Member]
|
|||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |||
Interest Costs, Capitalized During Period | $ 869 | $ 782 | $ 322 |
Discontinued Operations Fair Value Measurements of Discontinued Operations (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
|||||||
Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period Start | $ 266 | $ 381 | ||||||
Unrealized losses | 1,318 | 303 | ||||||
Unrealized gains | 751 | 188 | ||||||
Settlements | (96) | 0 | ||||||
Transfers Into Level 3 | 0 | [1] | 0 | [1] | ||||
Transfers out of Level 3 | 0 | [2] | 0 | [2] | ||||
Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period End | (397) | 266 | ||||||
Fair Value, Net Measured on Recurring Basis, Change in Unrealized Gain (Loss) Relating to Instruments Still Held as of Period End | (101) | (302) | ||||||
Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 0 | |||||||
Derivative Liabilities | 0 | |||||||
Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 166,571 | |||||||
Derivative Liabilities | 143,558 | |||||||
Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 7,976 | |||||||
Derivative Liabilities | 2,463 | |||||||
Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | (122,639) | |||||||
Derivative Liabilities | (122,639) | |||||||
Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | (1,410) | |||||||
Derivative Liabilities | (5,368) | |||||||
Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 50,498 | |||||||
Derivative Liabilities | 18,014 | |||||||
Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period Start | 5,513 | (937) | ||||||
Unrealized losses | (8,631) | (2,525) | ||||||
Unrealized gains | 6,094 | 7,295 | ||||||
Settlements | (2,248) | (1,179) | ||||||
Transfers Into Level 3 | 0 | [1] | 1,457 | [1] | ||||
Transfers out of Level 3 | 0 | [2] | 1,402 | [2] | ||||
Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period End | 728 | 5,513 | ||||||
Fair Value, Net Measured on Recurring Basis, Change in Unrealized Gain (Loss) Relating to Instruments Still Held as of Period End | (825) | 1,078 | ||||||
Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 0 | 0 | ||||||
Derivative Liabilities | 0 | 0 | ||||||
Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 789,537 | 166,405 | ||||||
Derivative Liabilities | 771,534 | 143,537 | ||||||
Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 6,139 | 7,976 | ||||||
Derivative Liabilities | 5,411 | 2,463 | ||||||
Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | (743,154) | (122,639) | ||||||
Derivative Liabilities | (743,154) | (122,639) | ||||||
Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 337 | (1,410) | ||||||
Derivative Liabilities | (7,707) | (5,368) | ||||||
Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 52,859 | 50,332 | ||||||
Derivative Liabilities | 26,084 | 17,993 | ||||||
Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 0 | |||||||
Derivative Liabilities | 0 | |||||||
Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 166 | |||||||
Derivative Liabilities | 21 | |||||||
Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 0 | |||||||
Derivative Liabilities | 0 | |||||||
Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 0 | |||||||
Derivative Liabilities | 0 | |||||||
Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 0 | |||||||
Derivative Liabilities | 0 | |||||||
Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Derivative Assets, Commodity Derivatives | 166 | |||||||
Derivative Liabilities | 21 | |||||||
Designated as Hedging Instrument [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Net | 10,658 | 10,548 | ||||||
Derivative Liability, Fair Value, Net | 30,253 | 26,913 | ||||||
Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Net | 5,256 | 11,000 | ||||||
Derivative Liability, Fair Value, Net | 403 | 1,568 | ||||||
Not Designated as Hedging Instrument [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Net | 0 | 0 | ||||||
Derivative Liability, Fair Value, Net | 112,667 | 61,168 | ||||||
Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Net | 828,347 | 173,502 | ||||||
Derivative Liability, Fair Value, Net | 807,187 | 154,408 | ||||||
Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Gross Asset | 55,413 | 142,013 | ||||||
Derivative Asset, Fair Value, Gross Liability | 13,740 | 107,795 | ||||||
Derivative Assets, Current [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Gross Asset | 0 | 10,952 | ||||||
Derivative Asset, Fair Value, Gross Liability | 0 | 1,452 | ||||||
Derivative Assets, Noncurrent [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Gross Asset | 0 | 48 | ||||||
Derivative Asset, Fair Value, Gross Liability | 0 | 71 | ||||||
Derivative Assets, Noncurrent [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Asset, Fair Value, Gross Asset | 76,629 | 9,757 | ||||||
Derivative Asset, Fair Value, Gross Liability | 54,784 | 3,099 | ||||||
Derivative Liabilities, Current [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Liability, Fair Value, Gross Asset | 5,256 | 0 | ||||||
Derivative Liability, Fair Value, Gross Liability | 403 | 45 | ||||||
Derivative Liabilities, Current [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Liability, Fair Value, Gross Asset | 691,453 | 20,588 | ||||||
Derivative Liability, Fair Value, Gross Liability | 729,309 | 39,051 | ||||||
Derivative Liabilities, Current [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Liability, Fair Value, Gross Asset | 0 | 166 | ||||||
Derivative Liability, Fair Value, Gross Liability | 0 | 21 | ||||||
Derivative Liabilities, Noncurrent [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Liability, Fair Value, Gross Asset | 0 | 0 | ||||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||||||
Derivative Liabilities, Noncurrent [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]
|
||||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||||||
Derivative Liability, Fair Value, Gross Asset | 4,852 | 978 | ||||||
Derivative Liability, Fair Value, Gross Liability | $ 9,354 | $ 4,442 | ||||||
|
Jointly Owned Facilities Jointly Owned Facilities (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2011
Oil and Gas [Member]
|
Dec. 31, 2010
Electric Utilities [Member]
|
Dec. 31, 2009
Electric Utilities [Member]
|
Dec. 31, 2011
Electric Utilities [Member]
Wyodak Plant [Member]
|
Dec. 31, 2011
Electric Utilities [Member]
Transmission Tie [Member]
|
Dec. 31, 2011
Electric Utilities [Member]
Wygen I I I Generating Facility [Member]
|
Dec. 31, 2009
Power Generation [Member]
|
Dec. 31, 2011
Power Generation [Member]
Wygen I Generating Facility [Member]
|
---|---|---|---|---|---|---|---|---|---|
Jointly Owned Utility Plant Interests [Line Items] | |||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 44.70% | 23.00% | 25.00% | 20.00% | 35.00% | 52.00% | 23.50% | 76.50% | |
Jointly Owned Utility Plant, Net Ownership Amount | $ 4,277,825 | ||||||||
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | 363,300 | 109,007 | 19,648 | 129,791 | 104,854 | ||||
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress | 1,847 | 718 | 0 | 249 | 880 | ||||
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | $ 78,539 | $ 46,104 | $ 4,061 | $ 5,328 | $ 23,046 |
Impairment of Long-Lived Assets Impairment of Long-Lived Assets (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
Mar. 31, 2009
|
|
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Impairment of long-lived assets | $ 0 | $ 0 | $ 43,301 | |
Natural Gas Price Per MCF, NYMEX | 4.12 | 4.38 | 3.87 | 3.63 |
Natural Gas Price Per MCF, Wellhead | 3.59 | 3.45 | 2.52 | 2.23 |
Crude Oil Price, per Barrel, NYMEX | 96.19 | 79.43 | 61.18 | 49.66 |
Crude Oil Price Per Barrel, Wellhead | 88.49 | 70.82 | 53.59 | 45.32 |
Business Description and Significant Accounting Policies Accounts Receivable (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
---|---|---|
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts Receivable | $ (1,661) | $ (2,294) |
Accounts receivable, net | 156,774 | 171,816 |
Electric Utilities [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts Receivable | (545) | (708) |
Accounts receivable, net | 63,379 | 69,869 |
Gas Utilities [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts Receivable | (1,011) | (1,425) |
Accounts receivable, net | 77,334 | 80,921 |
Oil and Gas [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts Receivable | (105) | (161) |
Accounts receivable, net | 11,177 | 6,052 |
Coal [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts Receivable | 0 | 0 |
Accounts receivable, net | 4,056 | 2,420 |
Power Generation [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts Receivable | 0 | 0 |
Accounts receivable, net | 282 | 307 |
Corporate [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts Receivable | 0 | 0 |
Accounts receivable, net | 546 | 12,247 |
Billed Revenues [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 98,292 | 114,162 |
Billed Revenues [Member] | Electric Utilities [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 42,773 | 51,005 |
Billed Revenues [Member] | Gas Utilities [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 39,353 | 41,970 |
Billed Revenues [Member] | Oil and Gas [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 11,282 | 6,213 |
Billed Revenues [Member] | Coal [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 4,056 | 2,420 |
Billed Revenues [Member] | Power Generation [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 282 | 307 |
Billed Revenues [Member] | Corporate [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 546 | 12,247 |
Unbilled Revenues [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 60,143 | 59,948 |
Unbilled Revenues [Member] | Electric Utilities [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 21,151 | 19,572 |
Unbilled Revenues [Member] | Gas Utilities [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 38,992 | 40,376 |
Unbilled Revenues [Member] | Oil and Gas [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 0 | 0 |
Unbilled Revenues [Member] | Coal [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 0 | 0 |
Unbilled Revenues [Member] | Power Generation [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | 0 | 0 |
Unbilled Revenues [Member] | Corporate [Member]
|
||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Trade | $ 0 | $ 0 |
Employee Benefit Plans Employee Benefit Plans Fair Value Measurements (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
---|---|---|---|
Money Market Funds [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 70 | ||
Registered Investment Company, Equity Fund [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 23,498 | ||
Common Collective Trust, Equity Fund [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 103,004 | ||
Common Collective Trust, Fixed Fund [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 48,024 | ||
Real Estate Funds [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 7,042 | ||
Pension Plans, Defined Benefit [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 221,722 | 220,164 | 176,503 |
Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 46,990 | 54,614 | |
Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 167,690 | 159,424 | |
Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 7,042 | 6,126 | |
Pension Plans, Defined Benefit [Member] | Money Market Funds [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Pension Plans, Defined Benefit [Member] | Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 70 | 0 | |
Pension Plans, Defined Benefit [Member] | Money Market Funds [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Money Market Funds [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Registered Investment Company, Equity Fund [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 27,070 | ||
Pension Plans, Defined Benefit [Member] | Registered Investment Company, Equity Fund [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 23,498 | 27,070 | |
Pension Plans, Defined Benefit [Member] | Registered Investment Company, Equity Fund [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Registered Investment Company, Equity Fund [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Other Investment Companies [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 23,422 | 27,544 | |
Pension Plans, Defined Benefit [Member] | Other Investment Companies [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 23,422 | 27,544 | |
Pension Plans, Defined Benefit [Member] | Other Investment Companies [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Other Investment Companies [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | 103-12 Investment Entities, Equity [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 10,329 | 11,246 | |
Pension Plans, Defined Benefit [Member] | 103-12 Investment Entities, Equity [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | 103-12 Investment Entities, Equity [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 10,329 | 11,246 | |
Pension Plans, Defined Benefit [Member] | 103-12 Investment Entities, Equity [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 25 | 174 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 25 | 174 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Equity Fund [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 106,786 | ||
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Equity Fund [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Equity Fund [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 103,004 | 106,786 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Equity Fund [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Fixed Fund [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 39,121 | ||
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Fixed Fund [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Fixed Fund [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 48,024 | 39,121 | |
Pension Plans, Defined Benefit [Member] | Common Collective Trust, Fixed Fund [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Real Estate Funds [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 6,126 | ||
Pension Plans, Defined Benefit [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 7,042 | 6,126 | |
Pension Plans, Defined Benefit [Member] | Structured Products [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 3,884 | ||
Pension Plans, Defined Benefit [Member] | Structured Products [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Pension Plans, Defined Benefit [Member] | Structured Products [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 3,884 | ||
Pension Plans, Defined Benefit [Member] | Structured Products [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | ||
Pension Plans, Defined Benefit [Member] | Insurance Contracts [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 2,424 | 2,097 | |
Pension Plans, Defined Benefit [Member] | Insurance Contracts [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Pension Plans, Defined Benefit [Member] | Insurance Contracts [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 2,424 | 2,097 | |
Pension Plans, Defined Benefit [Member] | Insurance Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Other Postretirement Benefit Plans, Defined Benefit [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 4,319 | 4,564 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 4,319 | 4,564 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | Common Collective Trust [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 4,319 | 4,564 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | Common Collective Trust [Member] | Fair Value, Inputs, Level 1 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | Common Collective Trust [Member] | Fair Value, Inputs, Level 2 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | 4,319 | 4,564 | |
Other Postretirement Benefit Plans, Defined Benefit [Member] | Common Collective Trust [Member] | Fair Value, Inputs, Level 3 [Member]
|
|||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0 | $ 0 |
Quarterly Historical Data (Unaudited) Quarterly Historical Data (Unaudited) (Details) (USD $)
|
3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2011
|
Sep. 30, 2011
|
Jun. 30, 2011
|
Mar. 31, 2011
|
Dec. 31, 2010
|
Sep. 30, 2010
|
Jun. 30, 2010
|
Mar. 31, 2010
|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
||||||||||||||||||||
Selected Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||
Revenue | $ 361,181,000 | $ 249,523,000 | $ 260,649,000 | $ 400,835,000 | $ 314,999,000 | [1] | $ 240,521,000 | [1] | $ 247,443,000 | [1] | $ 416,728,000 | [1] | $ 1,272,188,000 | $ 1,219,691,000 | $ 1,198,712,000 | |||||||||||||||
Operating income (loss) | 52,140,000 | 39,572,000 | 36,160,000 | 58,367,000 | 46,857,000 | [2] | 44,695,000 | [2] | 27,170,000 | [2] | 64,698,000 | [2] | 186,239,000 | 183,420,000 | 124,155,000 | |||||||||||||||
Income (Loss) from Continuing Operations | 18,754,000 | (11,163,000) | 3,706,000 | 29,068,000 | 34,631,000 | 10,493,000 | (10,688,000) | 28,705,000 | 40,365,000 | 63,141,000 | 77,269,000 | |||||||||||||||||||
Income (Loss) from Discontinued Operations, Net of Tax | 6,839,000 | 638,000 | 4,046,000 | (2,158,000) | (1,111,000) | 1,897,000 | 2,029,000 | 2,729,000 | ||||||||||||||||||||||
Net income (loss) | 25,593,000 | [3] | (10,525,000) | [3] | 7,752,000 | [3] | 26,910,000 | [3] | 33,520,000 | [2],[4] | 12,390,000 | [2],[4] | (8,659,000) | [2],[4] | 31,434,000 | [2],[4] | 49,730,000 | 68,685,000 | 81,555,000 | |||||||||||
Income (loss) from continuing operations, per share | $ 0.45 | $ (0.29) | $ 0.09 | $ 0.74 | $ 0.89 | $ 0.27 | $ (0.27) | $ 0.74 | $ 1.01 | $ 1.62 | $ 2 | |||||||||||||||||||
Income (loss) from discontinued operations, per share | $ 0.16 | $ 0.02 | $ 0.11 | $ (0.05) | $ (0.03) | $ 0.05 | $ 0.05 | $ 0.07 | $ 0.24 | $ 0.14 | $ 0.11 | |||||||||||||||||||
Total Income (loss) per share, basic | $ 0.61 | $ (0.27) | $ 0.2 | $ 0.69 | $ 0.86 | $ 0.32 | $ (0.22) | $ 0.81 | $ 1.25 | $ 1.76 | $ 2.11 | |||||||||||||||||||
Income (loss) from continuing operations, per share | $ 0.44 | $ (0.29) | $ 0.09 | $ 0.73 | $ 0.88 | $ 0.27 | $ (0.27) | $ 0.74 | $ 1.01 | $ 1.62 | $ 2 | |||||||||||||||||||
Income (loss) from discontinued operations, per share | $ 0.16 | $ 0.02 | $ 0.1 | $ (0.05) | $ (0.03) | $ 0.05 | $ 0.05 | $ 0.07 | $ 0.23 | $ 0.14 | $ 0.11 | |||||||||||||||||||
Total Income (loss) per share, per share, diluted | $ 0.6 | $ (0.27) | $ 0.19 | $ 0.68 | $ 0.85 | $ 0.32 | $ (0.22) | $ 0.81 | $ 1.24 | $ 1.76 | $ 2.11 | |||||||||||||||||||
Common Stock, Dividends, Per Share | $ 0.365 | $ 0.365 | $ 0.365 | $ 0.365 | $ 0.36 | $ 0.36 | $ 0.36 | $ 0.36 | $ 1.46 | $ 1.44 | $ 1.42 | |||||||||||||||||||
Common Stock Prices Per Share, High | $ 34.47 | $ 32.22 | $ 34.85 | $ 33.64 | $ 33.42 | $ 33.31 | $ 34.49 | $ 30.83 | ||||||||||||||||||||||
Common Stock Price Per Share, Low | $ 29.10 | $ 25.83 | $ 28.12 | $ 29.76 | $ 29.32 | $ 27.79 | $ 27.34 | $ 25.65 | ||||||||||||||||||||||
Increase Decrease in Fair Value of Unhedged Derivative Instrument After Tax | (900,000) | (24,900,000) | (5,100,000) | 3,600,000 | 17,200,000 | (8,900,000) | (16,200,000) | (2,000,000) | ||||||||||||||||||||||
Gain (Loss) on Sale of Operating Assets | 6,200,000 | 2,700,000 | 0 | 8,921,000 | [5] | 25,971,000 | ||||||||||||||||||||||||
Gain (Loss) on Disposition of Assets Net of Tax | $ 4,100,000 | $ 1,700,000 | ||||||||||||||||||||||||||||
|
Long-Term Debt Debt Issuance (Details) (Parent [Member], USD $)
|
12 Months Ended | |||||
---|---|---|---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
|||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 774,959,000 | $ 674,930,000 | ||||
Senior Unsecured Notes Due 2020 [Member]
|
||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | 200,000,000 | [1] | 200,000,000 | [1] | ||
Long-term Debt, Maturity Date | Jul. 15, 2020 | |||||
Long-term Debt, Fixed Interest Rate | 5.88% | |||||
Proceeds from Issuance of Senior Long-term Debt | 198,700,000 | |||||
Long Term Term Loan [Member]
|
||||||
Debt Instrument [Line Items] | ||||||
Long-term Debt | $ 100,000,000 | $ 0 | ||||
Long-term Debt, Maturity Date | Sep. 30, 2013 | |||||
Debt Instrument, Interest Rate Terms | 1.375% | |||||
Long-term Debt, Variable Interest Rate at Period End | 1.69% | |||||
|
Schedule I Disclosures for Parent Company Only Schedule I, Derivatives Not Designated as Hedging Instruments Statement of Financial Performance and Financial Position Location (Details) (Not Designated as Hedging Instrument [Member], USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
|
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Net | $ (55,383) | $ (28,505) | $ 45,837 |
Parent [Member]
|
|||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Net | (55,383) | (28,505) | 45,837 |
Parent [Member] | Interest Rate Swap [Member] | Unrealized Gain (Loss) on Interest Rate Swaps [Member]
|
|||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Net | (42,010) | (15,193) | 55,653 |
Parent [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
|
|||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative Instruments, Gain (Loss) Recognized in Income, Net | $ (13,373) | $ (13,312) | $ (9,816) |
Common Stock Dividend Reinvestment and Stock Purchase Plan (Details) (DRIP [Member], USD $)
|
12 Months Ended | |
---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
DRIP [Member]
|
||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Common Stock Purchase Percentage of Recent Average Market Price | 100.00% | |
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 103,000 | 106,000 |
Share-based Compensation Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ 31.23 | $ 29.57 |
Stock Unissued Shares Dividend Reinvestment Plan | 453,000 | 190,000 |
Schedule I Disclosures for Parent Company Only Schedule I, Fair Value Assets and Liabilites Measured on Recurring Basis (Details) (Interest Rate Swap [Member], Fair Value, Measurements, Recurring [Member], USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
---|---|---|
Fair Value, Inputs, Level 1 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | $ 0 | $ 0 |
Fair Value, Inputs, Level 2 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 122,867 | 75,779 |
Fair Value, Inputs, Level 3 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 122,867 | 75,779 |
Parent [Member] | Fair Value, Inputs, Level 1 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Parent [Member] | Fair Value, Inputs, Level 2 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 109,869 | 64,703 |
Parent [Member] | Fair Value, Inputs, Level 3 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Parent [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | $ 109,869 | $ 64,703 |
Schedule I Disclosures for Parent Company Only Schedule I, Fair Value by Balance Sheet Grouping (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
Dec. 31, 2008
|
---|---|---|---|---|
Derivatives, Carrying Amount and Fair Value [Line Items] | ||||
Cash and cash equivalents, at carrying value | $ 21,628 | $ 16,437 | ||
Notes payable | 345,000 | 249,000 | ||
Long-term Debt, including current maturities | 1,282,882 | 1,191,231 | ||
Carrying (Reported) Amount, Fair Value Disclosure [Member]
|
||||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||||
Cash and cash equivalents, at carrying value | 21,628 | 16,437 | ||
Derivative Liabilities | 133,400 | 82,514 | ||
Notes payable | 345,000 | 249,000 | ||
Long-term Debt, including current maturities | 1,282,882 | 1,191,231 | ||
Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||||
Cash and cash equivalents, fair value | 21,628 | 16,437 | ||
Notes payable, fair value | 345,000 | 249,000 | ||
Long-term debt, including curent maturities at fair value | 1,464,289 | 1,290,519 | ||
Parent [Member]
|
||||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||||
Cash and cash equivalents, at carrying value | 3,114 | 219 | 2,273 | 17,184 |
Derivative Liabilities | 109,870 | 64,703 | ||
Notes payable | 345,000 | 249,000 | ||
Long-term Debt, including current maturities | 774,959 | 674,930 | ||
Parent [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||||
Derivatives, Carrying Amount and Fair Value [Line Items] | ||||
Cash and cash equivalents, fair value | 3,114 | 219 | ||
Derivative Liability, Fair Value, Gross Liability | 109,870 | 64,703 | ||
Notes payable, fair value | 345,000 | 249,000 | ||
Long-term debt, including curent maturities at fair value | $ 851,241 | $ 743,738 |
Common Stock Common Stock Equity Issuance (Details) (USD $)
In Thousands, except Share data, unless otherwise specified |
12 Months Ended |
---|---|
Dec. 31, 2011
|
|
Forward Contract Indexed to Issuer's Equity [Line Items] | |
Equity Issuance, Date | Nov. 10, 2010 |
Stock Issued During Period, Value, New Issues | $ 119,630 |
Parent [Member]
|
|
Forward Contract Indexed to Issuer's Equity [Line Items] | |
Sale of Stock, Transaction Date | Nov. 01, 2011 |
Stock Issued During Period, Value, New Issues | 119,600 |
Parent [Member] | Forward Equity Agreement Over Allotment Shares [Member]
|
|
Forward Contract Indexed to Issuer's Equity [Line Items] | |
Forward Equity Issuance OverAllotment | 413,519 |
Parent [Member] | Forward Equity Agreement [Member]
|
|
Forward Contract Indexed to Issuer's Equity [Line Items] | |
Forward Contract Indexed to Issuer's Equity, Shares | 4,000,000 |
Common Stock [Member]
|
|
Forward Contract Indexed to Issuer's Equity [Line Items] | |
Stock Issued During Period, Shares, New Issues | 4,413,519 |
Stock Issued During Period, Value, New Issues | $ 4,414 |
Common Stock Short-Term Incentive Plan (Details) (USD $)
Share data in Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Short Term Incentive Plan, Vested in Period, Total Intrinsic Value | $ 0 | $ 0 | |
Short-term Incentive Plan Expected in Future Year, Total Intrinsic Value | 100,000 | ||
Short Term Incentive Plan [Member]
|
|||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Short-Term Incentive Plan, Shares Issued in Period | 14,111 | 9,625 | 47,331 |
Short Term Incentive Plan, Vested in Period, Total Intrinsic Value | $ 400,000 |
Long-Term Debt Deferred Financing Costs (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
|
Senior Unsecured Notes due 2013 [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | $ 309 | ||
Amortization Expense for Deferred Financing Costs | 218 | 218 | 218 |
Senior Unsecured Notes Due 2014 [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 1,097 | ||
Amortization Expense for Deferred Financing Costs | 462 | 462 | 289 |
Senior Unsecured Notes Due 2020 [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 1,428 | ||
Amortization Expense for Deferred Financing Costs | 167 | 77 | 0 |
First Mortgage Bonds Due 2032 [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 684 | ||
Amortization Expense for Deferred Financing Costs | 33 | 33 | 33 |
First Mortgage Bonds Due 2039 [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 2,113 | ||
Amortization Expense for Deferred Financing Costs | 76 | 76 | 12 |
First Mortgage Bonds Due 2037 [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 797 | ||
Amortization Expense for Deferred Financing Costs | 31 | 31 | 31 |
Project Financing Debt Due 2016 [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 4,214 | ||
Amortization Expense for Deferred Financing Costs | 1,012 | 1,036 | 60 |
Deferred Financing Costs, Other [Member]
|
|||
Debt Instrument [Line Items] | |||
Deferred Finance Costs Remaining, Noncurrent | 816 | ||
Amortization Expense for Deferred Financing Costs | $ 70 | $ 74 | $ 67 |
Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
---|---|---|
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents, at carrying value | $ 21,628 | $ 16,437 |
Restricted cash, at carrying value | 9,254 | 4,260 |
Notes payable, at carrying value | 345,000 | 249,000 |
Long-term debt, including current maturities at carrying value | 1,282,882 | 1,191,231 |
Carrying Amount
|
||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents, at carrying value | 21,628 | 16,437 |
Restricted cash, at carrying value | 9,254 | 4,260 |
Total derivative assets | 20,554 | 15,335 |
Total derivative liabilities | 133,400 | 82,514 |
Notes payable, at carrying value | 345,000 | 249,000 |
Long-term debt, including current maturities at carrying value | 1,282,882 | 1,191,231 |
Fair Value
|
||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents, fair value | 21,628 | 16,437 |
Restricted cash, fair value | 9,254 | 4,260 |
Total derivative asset at fair value | 20,554 | 15,335 |
Total derivative liability, fair value | 133,400 | 82,514 |
Notes payable, fair value | 345,000 | 249,000 |
Long-term debt, including current maturities at fair value | 1,464,289 | 1,290,519 |
Project Financing Debt Due 2016 [Member]
|
||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Restricted cash, at carrying value | $ 3,600 |
Employee Benefit Plans
|
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2011
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Employee Benefit Plans [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Defined Contribution Plans We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation to the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company Matching Contribution for all participants and for certain eligible participants a Company Retirement Contribution based on the participant's age and years of service. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20% per year with 100% vesting when the participant has 5 years of service with the Company. Funded Status of Benefit Plans The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. Except for our regulated utilities, the unrecognized net periodic benefit cost is recorded within Accumulated other comprehensive income (loss), net of tax. For our regulated utilities, we applied accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost was alternatively recorded as a regulatory asset or regulatory liability, net of tax. The measurement date for all plans is December 31. As of December 31, 2011, the funded status of our Defined Benefit Pension Plan was $104.0 million; the funded status of our Non-Qualified Defined Benefit Retirement Plan was $30.0 million; and the funded status of our Non-Pension Defined Benefit Postretirement Plan was $46.0 million. Defined Benefit Pension Plan We have three non-contributory defined benefit pension plans (the Pension Plans). As of January 1, 2012, all Pension Plans have been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Plans were frozen. The benefits for the plans are based on years of service and calculations of average earnings during a specific time period prior to retirement. In 2011, the Cheyenne Light Pension Plan was amended to freeze the benefits of certain bargaining unit employees. This amendment was effective as of January 1, 2012. Our Pension Plan funding policy is in accordance with the federal government's funding requirements. The Pension Plans' assets are held in trust and consist primarily of equity and fixed income investments. The Investment Policy for the Pension Plans is to seek to achieve the following long-term objectives: 1) a rate of return in excess of the annualized inflation rate based on a five year moving average; 2) a rate of return that meets or exceeds the assumed actuarial rate of return as stated in the Plan's actuarial report; 3) a rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates on a moving three year average, and 4) maintenance of sufficient income and liquidity to pay monthly retirement benefits. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets. The policy contains certain prohibitions on transactions in separately managed portfolios in which the Pension Plans may invest, including prohibitions on short sales. The Pension Plans' expected long-term rate of return on assets assumptions are based upon the weighted-average expected long-term rate of return for each individual asset class. The asset class weighting is determined using the target allocation for each class in the Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from adjusted long-term historical returns for the asset class. It is anticipated that long-term future returns will not achieve historical results. Our Pension Plan funding policy is in accordance with the federal government's funding requirements. The Pension Plans' assets are held in trust and consist primarily of equity and fixed income investments. The expected long-term rate of return for equity investments was 8.75% and 9.25% for the 2011 and 2010 plan years, respectively. Plan Assets The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows:
Supplemental Non-qualified Defined Benefit Retirement Plans We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to a graded vesting schedule at 20% per year over 5 years and are not funded by the Company. Plan Assets We fund the NQDC on a cash basis as benefits are paid; therefore, assets of the plan are $0.0 million. Non-pension Defined Benefit Postretirement Plans We sponsor retiree healthcare plans (the Healthcare Plans) for all employees who meet certain age and service requirements at retirement and who are entitled to postretirement healthcare benefits. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the plans periodically. A portion of the Healthcare Plan is pre-funded via VEBAs. It has been determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. Plan Assets We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Energy Plan provides for partial pre-funding via VEBAs. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees of Black Hills Energy located in the states of Kansas and Iowa. We do not pre-fund the Postretirement Healthcare Plan for those employees outside Kansas and Iowa. Plan Contributions Contributions to the Healthcare Plans and the Supplemental Plans are made in the form of benefit payments. Contributions to our employee benefit plans were as follows (in thousands):
We expect to make contributions to our employee benefit plans as follows (in thousands):
Fair Value Measurements As required by accounting standards for Compensation - Retirement Benefits, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):
The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plan's level 3 assets for the period ended December 31 (in thousands):
Additional information about plan assets, including methods and assumption used to estimate the fair value of these assets, is as follows: Registered Investment Companies: Investments are valued at the closing price reported on the active market on which the individual securities are traded. 103-12 Investment Entities: The trustee determines the value of the pooled trust fund and the units thereof in U.S. Dollars as of (i) each daily valuation date, and (ii) each other day designated by mutual agreement between the trustee and the investment manager. As of each valuation date, the trustee shall determine the total value of the assets of the pooled trust fund, including the value of any interest accrued or dividends payable with respect thereto, shall be determined and securities valued as of the close of business in the applicable trading market coinciding with or next preceding the close of business on the New York Stock Exchange. Common Collective Trust: The Pension Plan owns units of the Common Collective Trust funds that they are utilizing in their portfolio. The value of each unit of any fund as of any valuation date shall be determined by calculating the total value of such fund's assets as of the close of business on such valuation date, deducting its total liabilities as of such time and date, and then dividing the so-determined net asset value of such fund by the total number of units of such fund outstanding the date of valuation. Insurance Contract: These investments are valued on a cash basis on any given valuation date. Structured Products: Investments are created through the process of financial engineering, (that is, by combining underlying securities like equity, bonds, or indices with derivatives). The value of derivative securities, such as options, forwards and swaps is determined by (respectively, derives from) the prices of the underlying securities. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the statement of financial position, components of the net periodic expense and elements of accumulated other comprehensive income (in thousands): Benefit Obligations
A reconciliation of the fair value of Plan assets was as follows (in thousands):
____________________ (a) Asset of VEBA Amounts recognized in the Consolidated Balance Sheet consist of (in thousands):
Accumulated Benefit Obligation
Components of Net Periodic Expense
Accumulated Other Comprehensive Income In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
The amounts in accumulated other comprehensive income, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2012 are as follows (in thousands):
Assumptions
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The healthcare benefit obligation was determined at December 31, 2011, using an initial healthcare trend rate of 9.01% trending down to an ultimate rate of 4.50% in 2028, and at December 31, 2010, using an initial healthcare trend rate of 9.51% trending down to an ultimate rate of 4.50% in 2027. We do not pre-fund our non-qualified pension plans or two of the three postretirement benefit plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Retiree Healthcare Plans (in thousands):
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
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Schedule I Disclosures for Parent Company Only Schedule I, Notes Payable (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |
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Dec. 31, 2011
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Dec. 31, 2010
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Short-term Debt [Line Items] | ||
Notes payable | $ 345,000 | $ 249,000 |
Letters of Credit Outstanding, Amount | 43,700 | 46,865 |
Parent [Member]
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Short-term Debt [Line Items] | ||
Notes payable | 345,000 | 249,000 |
Parent [Member] | Line of Credit [Member] | Revolving Credit Facility, Existing [Member]
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Short-term Debt [Line Items] | ||
Line of Credit Facility, Expiration Date | 4/14/2013 | |
Notes payable | 195,000 | 149,000 |
Letters of Credit Outstanding, Amount | 43,700 | 46,865 |
Line of Credit Facility, Commitment Fee Percentage | 0.50% | |
Parent [Member] | Loans Payable [Member] | Corporate Term Loan due June 2012 [Member]
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Short-term Debt [Line Items] | ||
Notes payable | 150,000 | 0 |
Letters of Credit Outstanding, Amount | $ 0 | $ 0 |
Term Loan, Maturity Date | Jun. 24, 2012 | |
Debt Instrument, Basis Spread on Variable Rate | 1.25% | |
Debt Instrument, Interest Rate at Period End | 1.56% | |
Parent [Member] | Base Rate Option [Member] | Line of Credit [Member] | Revolving Credit Facility, Existing [Member]
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Short-term Debt [Line Items] | ||
Line of Credit Facility, Interest Rate at Period End | 1.75% | |
Parent [Member] | Eurodollar Option [Member] | Line of Credit [Member] | Revolving Credit Facility, Existing [Member]
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Short-term Debt [Line Items] | ||
Line of Credit Facility, Interest Rate at Period End | 2.75% | |
Parent [Member] | Letters of Credit [Member] | Line of Credit [Member] | Revolving Credit Facility, Existing [Member]
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Short-term Debt [Line Items] | ||
Line of Credit Facility, Interest Rate at Period End | 2.75% |
Employee Benefit Plans Employee Benefit Plans (Tables)
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Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Allocation of Plan Assets [Table Text Block] | The percentages of total plan asset fair value by investment category for our Pension Plans at December 31 were as follows:
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Schedule of Defined Contribution Plans Contributions [Table Text Block] | Contributions to the Healthcare Plans and the Supplemental Plans are made in the form of benefit payments. Contributions to our employee benefit plans were as follows (in thousands):
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Expected Future Contributions Defined Benefit Plans [Table Text Block] | We expect to make contributions to our employee benefit plans as follows (in thousands):
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Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The following tables set forth, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):
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Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The following tables present the changes in level 3 recurring fair value (in thousands):
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Schedule of Changes in Projected Benefit Obligations [Table Text Block] |
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Schedule of Changes in Fair Value of Plan Assets [Table Text Block] | A reconciliation of the fair value of Plan assets was as follows (in thousands):
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Schedule of Amounts Recognized in Balance Sheet [Table Text Block] | Amounts recognized in the Consolidated Balance Sheet consist of (in thousands):
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Schedule of Accumulated and Projected Benefit Obligations [Table Text Block] | Accumulated Benefit Obligation
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Components of net periodic benefit cost | Components of Net Periodic Expense
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Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block] | In accordance with accounting standards for defined benefit plans, amounts included in Accumulated other comprehensive income (loss), after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
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Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block] | The amounts in accumulated other comprehensive income, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2012 are as follows (in thousands):
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Schedule of Assumptions Used [Table Text Block] | Assumptions
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Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block] | The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Retiree Healthcare Plans (in thousands):
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Schedule of Expected Benefit Payments [Table Text Block] | The following benefit payments, which reflect future service, are expected to be paid (in thousands):
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Pension Plans, Defined Benefit [Member]
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Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):
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Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plan's level 3 assets for the period ended December 31 (in thousands):
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Defined Benefit Postretirement Health Coverage [Member]
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Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] |
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Notes Payable Notes Payable (Tables)
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12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Schedule of Short-term Debt | We had the following short-term debt outstanding as of the Consolidated Balance Sheet dates (in thousands):
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Deferred Financing Costs [Table Text Block] | Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):
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Credit Facility Covenants | The Revolving Credit Facility includes the following covenants that we must comply with at the end of each quarter (dollars, in thousands). We were in compliance with these covenants as of December 31, 2011.
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Revolving Credit Facility, Existing [Member]
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Line of Credit Facility | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Financing Costs [Table Text Block] | Deferred financing costs are being amortized over the term of the Revolving Credit Facility and are included in Interest expense on the accompanying Consolidated Statements of Income as follows (in thousands):
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Long-Term Debt Aggregate Maturities of Long Term Debt (Details) (USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
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Debt Instrument [Line Items] | |
Long-term Debt, Current Maturities | $ 2,473 |
Long-term Debt, Maturities, Repayments of Principal in Year Two | 328,973 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 262,473 |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 6,964 |
Long-term Debt, Maturities, Repayments of Principal in Year Five | 85,101 |
Long-term Debt, Maturities, Repayments of Principal after Year Five | $ 597,054 |
Income Taxes Interest and penalties included in income tax expense (Details) (USD $)
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12 Months Ended | ||
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Dec. 31, 2011
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Dec. 31, 2010
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Dec. 31, 2009
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Interest Expense in Income Tax Examination [Line Items] | |||
Unrecognized Tax Benefits, Interest Expense (Income) Included in Income Tax (Expense) Benefit | $ 1,400,000 | $ 2,300,000 | $ 1,200,000 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | $ 4,500,000 | $ 3,100,000 | |
Income Tax Examination, Year(s) under Examination | 2007 through 2009 |
Fair Value Measurements Fair Value Measurements (Tables)
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Dec. 31, 2011
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Derivative Instruments, Gain (Loss) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of fair value assets and liabilities measured on recurring basis | The following tables set forth, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):
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Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The following tables present the changes in level 3 recurring fair value (in thousands):
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Fair value and balance sheet classification of derivative instruments | The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31 (in thousands):
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Cash Flow Hedging
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Derivative Instruments, Gain (Loss) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gains and losses recognized in income | The impact of cash flow hedges on our Consolidated Statements of Income and Balance Sheets for the years ended are presented as follows (in thousands):
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Derivatives Not Designated as Hedge Instruments [Member]
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Derivative Instruments, Gain (Loss) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block] | The impact of derivative instruments that have not been designated as hedging instruments on our Consolidated Statements of Income for the years ended December 31 was as follows (in thousands):
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Guarantees Guarantees (Tables)
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12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2011
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20. Guarantees [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Guarantor Obligations [Table Text Block] | We had the following guarantees in place (in thousands):
|
Fair Value Measurements Fair Value Measurements (Details) (Fair Value, Measurements, Recurring [Member], USD $)
In Thousands, unless otherwise specified |
Dec. 31, 2011
|
Dec. 31, 2010
|
---|---|---|
Fair Value, Inputs, Level 1 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money Market Funds | $ 6,005 | $ 8,050 |
Derivative Assets, Total | 6,005 | 8,050 |
Derivative Liabilities, Total | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Commodity derivatives [Member] | Oil and Gas [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Commodity derivatives [Member] | Utilities Group [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Fair Value, Inputs, Level 2 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money Market Funds | 0 | 0 |
Derivative Assets, Total | 365 | 4,713 |
Derivative Liabilities, Total | 132,230 | 82,514 |
Fair Value, Inputs, Level 2 [Member] | Commodity derivatives [Member] | Oil and Gas [Member]
|
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Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 9,885 | 10,281 |
Derivative, Liabilities, Fair Value Disclosure | 2,207 | 5,115 |
Fair Value, Inputs, Level 2 [Member] | Commodity derivatives [Member] | Utilities Group [Member]
|
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Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | (9,520) | (5,568) |
Derivative, Liabilities, Fair Value Disclosure | 7,156 | 1,620 |
Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 122,867 | 75,779 |
Fair Value, Inputs, Level 3 [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money Market Funds | 0 | 0 |
Derivative Assets, Total | 768 | 266 |
Derivative Liabilities, Total | 1,165 | 0 |
Fair Value, Inputs, Level 3 [Member] | Commodity derivatives [Member] | Oil and Gas [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 768 | 266 |
Derivative, Liabilities, Fair Value Disclosure | 1,165 | 0 |
Fair Value, Inputs, Level 3 [Member] | Commodity derivatives [Member] | Utilities Group [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Counterparty Netting [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money Market Funds | 0 | 0 |
Derivative Assets, Total | 5 | 0 |
Derivative Liabilities, Total | 5 | 0 |
Counterparty Netting [Member] | Commodity derivatives [Member] | Oil and Gas [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 5 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 5 | 0 |
Counterparty Netting [Member] | Commodity derivatives [Member] | Utilities Group [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Counterparty Netting [Member] | Interest Rate Swap [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Cash Collateral [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money Market Funds | 0 | 0 |
Derivative Assets, Total | 19,416 | 10,355 |
Derivative Liabilities, Total | 0 | 0 |
Cash Collateral [Member] | Commodity derivatives [Member] | Oil and Gas [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 0 | 0 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Cash Collateral [Member] | Commodity derivatives [Member] | Utilities Group [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 19,416 | 10,355 |
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Cash Collateral [Member] | Interest Rate Swap [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | 0 | 0 |
Total Estimate of Fair Value, Fair Value Disclosure [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Money Market Funds | 6,005 | 8,050 |
Derivative Assets, Total | 26,559 | 23,384 |
Derivative Liabilities, Total | 133,400 | 82,514 |
Total Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity derivatives [Member] | Oil and Gas [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 10,658 | 10,547 |
Derivative, Liabilities, Fair Value Disclosure | 3,377 | 5,115 |
Total Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity derivatives [Member] | Utilities Group [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Assets, Commodity Derivatives | 9,896 | 4,787 |
Derivative, Liabilities, Fair Value Disclosure | 7,156 | 1,620 |
Total Estimate of Fair Value, Fair Value Disclosure [Member] | Interest Rate Swap [Member]
|
||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Liabilities, Fair Value Disclosure | $ 122,867 | $ 75,779 |
Employee Benefit Plans Changes in Benefit Obligation (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
|
Dec. 31, 2010
|
Dec. 31, 2009
|
|
Pension Plans, Defined Benefit [Member]
|
|||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Defined Benefit Plan, Benefit Obligation, Period Start | $ 280,623 | $ 256,400 | |
Defined Benefit Plan, Service Cost | 5,421 | 6,131 | 7,587 |
Defined Benefit Plan, Interest Cost | 14,929 | 15,091 | 14,715 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 36,543 | 13,663 | |
Defined Benefit Plan, Plan Amendments | 0 | 261 | |
Defined Benefit Plan, Benefits Paid | (11,178) | (9,949) | |
Defined Benefit Plan, Curtailments | (394) | (974) | |
Defined Benefit Plan Medicare Part D | 0 | 0 | |
Defined Benefit Plan, Contributions by Plan Participants | 0 | 0 | |
Defined Benefit Plan, Benefit Obligation, Period End | 325,944 | 280,623 | 256,400 |
Supplemental Employee Retirement Plans, Defined Benefit [Member]
|
|||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Defined Benefit Plan, Benefit Obligation, Period Start | 24,725 | 21,611 | |
Defined Benefit Plan, Service Cost | 1,028 | 685 | |
Defined Benefit Plan, Interest Cost | 1,298 | 1,284 | |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 4,128 | 2,039 | |
Defined Benefit Plan, Plan Amendments | 0 | 0 | |
Defined Benefit Plan, Benefits Paid | (956) | (894) | |
Defined Benefit Plan, Curtailments | 0 | 0 | |
Defined Benefit Plan Medicare Part D | 0 | 0 | |
Defined Benefit Plan, Contributions by Plan Participants | 0 | 0 | |
Defined Benefit Plan, Benefit Obligation, Period End | 30,223 | 24,725 | |
Other Postretirement Benefit Plans, Defined Benefit [Member]
|
|||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||
Defined Benefit Plan, Benefit Obligation, Period Start | 46,304 | 46,396 | |
Defined Benefit Plan, Service Cost | 1,498 | 1,509 | 1,060 |
Defined Benefit Plan, Interest Cost | 2,168 | 2,446 | 2,202 |
Defined Benefit Plan, Actuarial Net (Gains) Losses | 3,017 | 961 | |
Defined Benefit Plan, Plan Amendments | (160) | (2,239) | |
Defined Benefit Plan, Benefits Paid | (4,963) | (5,198) | |
Defined Benefit Plan, Curtailments | 0 | 0 | |
Defined Benefit Plan Medicare Part D | 188 | 559 | |
Defined Benefit Plan, Contributions by Plan Participants | 2,089 | 1,870 | |
Defined Benefit Plan, Benefit Obligation, Period End | $ 50,141 | $ 46,304 | $ 46,396 |
Business Description and Significant Accounting Policies Schedule of Intangible Assets (Details) (USD $)
|
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
years
|
Dec. 31, 2010
|
Dec. 31, 2009
|
|
Finite-Lived Intangible Assets [Line Items] | |||
Finite-Lived Intangible Assets, Useful Life, Maximum | 20 | ||
Finite-Lived Intangible Assets [Roll Forward] | |||
Intangible assets, net, beginning balance | $ 4,069,000 | $ 4,309,000 | $ 4,884,000 |
Intangible asset, additions (adjustments) | 0 | 0 | 365,000 |
Intangible assets, amortization expense | (226,000) | (240,000) | (210,000) |
Intangible assets, net, ending balance | 3,843,000 | 4,069,000 | 4,309,000 |
Future Amortization Expense, Year One | 200,000 | ||
Future Amortization Expense, Year Two | 200,000 | ||
Future Amortization Expense, Year Three | 200,000 | ||
Future Amortization Expense, Year Four | 200,000 | ||
Future Amortization Expense, Year Five | $ 200,000 |
Comprehensive Income Comprehensive Income (Loss) (Tables)
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Dec. 31, 2011
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Other Comprehensive (Loss) Income [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Comprehensive Income (Loss) [Table Text Block] | The following table displays the related tax effects allocated to each component of Other comprehensive income (loss) for the years ended December 31 (in thousands):
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Balances by classification included within Accumulated Other Comprehensive Income (Loss) | Balances by classification included within Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheets were as follows (in thousands):
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Recently Adopted and Recently Issued Accounting Standards and Legislation
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12 Months Ended |
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Dec. 31, 2011
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New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recently Adopted and Recently Issued Accounting Standards and Legislation | RECENTLY ISSUED AND ADOPTED ACCOUNTING PRONOUNCEMENTS AND LEGISLATION Recently Adopted Accounting Standards Other Comprehensive Income, ASU No. 2011-05 and ASU 2011-12 FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of reporting of comprehensive income. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU No. 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. In December 2011, FASB issued ASU 2011-12. ASU 2011-12 indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income. We have elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements and provided additional details in notes to the financial statements, but did not have any other impact on our consolidated financial statements. See additional Comprehensive Income Statement and additional disclosures in Note 15. Fair Value Measurements and Disclosures, ASC 820 The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosure requirements related to fair value measurements. This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives within our Oil and Gas segment, interest rate swap instruments, and other miscellaneous financial instruments. In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements, disclosure of inputs and techniques used in valuation and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us January 1, 2010, except the disclosures related to purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which were effective January 1, 2011. The guidance requires additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 4. Extractive Activities — Oil and Gas Reserves (SEC Release #33-8995), ASC 932-10-S99 The FASB issued an accounting standards update which aligns the oil and gas reserve estimation and disclosure requirements with the SEC released Final Rule, "Modernization of Oil and Gas Reporting," which amended the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technology advances. Key revisions include the ability to include non-traditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the oil and gas prices used to determine reserves from the period-end price to a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months before the end of the reporting period. The amendment was effective for reporting periods ending on or after December 31, 2009. The implementation of this SEC requirement resulted in additional depletion expense of $1.3 million in the fourth quarter of 2009. Dodd-Frank Wall Street Reform and Consumer Protection Act In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated, including swap transactions in the over-the-counter market. Among other things, Dodd-Frank (i) mandates the clearing of some swaps through regulated central clearing organizations and the trading of clearing swaps through regulated exchanges or swap execution facilities, in each case subject to certain key exemptions, and (ii) authorizes regulators to establish collateral and margin requirements for certain swap transactions that are not cleared. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users, and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. In December 2011, the SEC issued Final Rule 33-9286 providing requirements for Section 1503 of Dodd-Frank. This release requires issuers that are operators of a coal mine to disclose information concerning mine safety violations or other regulatory matters. The required information for our WRDC coal mine is included in Exhibit 95 of this Form 10-K. Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required in order to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank. We will continue to evaluate the impact as these rules become available. Recently Issued Accounting Pronouncements and Legislation Intangibles - Goodwill and Other, ASU No. 2011-08 In September 2011, the FASB issued an amendment to an existing accounting standard, which provides an option to perform a qualitative assessment to determine whether further impairment testing on goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of this standard will not have a material impact on our financial statements. Fair Value Measurement, ASU No. 2011-04 FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. This amendment changes the wording used to describe fair value and requires additional disclosures. We do not expect this amendment, which is effective for interim and annual periods beginning after December 31, 2011, to have an impact on our financial position, results of operations, or cash flows. |
Schedule I Disclosures for Parent Company Only Schedule I, Narrative (Details) (USD $)
In Thousands, except Share data, unless otherwise specified |
12 Months Ended |
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Dec. 31, 2011
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Condensed Financial Statements, Captions [Line Items] | |
Equity Issuance, Date | Nov. 10, 2010 |
Stock Issued During Period, Value, New Issues | $ 119,630 |
Parent [Member]
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Condensed Financial Statements, Captions [Line Items] | |
Sale of Stock, Transaction Date | Nov. 01, 2011 |
Stock Issued During Period, Value, New Issues | 119,600 |
Forward Equity Agreement [Member] | Parent [Member]
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Condensed Financial Statements, Captions [Line Items] | |
Forward Contract Indexed to Issuer's Equity, Shares | 4,000,000 |
Forward Equity Agreement Over Allotment Shares [Member] | Parent [Member]
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Condensed Financial Statements, Captions [Line Items] | |
Forward Equity Issuance OverAllotment | 413,519 |
Common Stock [Member]
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Condensed Financial Statements, Captions [Line Items] | |
Stock Issued During Period, Shares, New Issues | 4,413,519 |
Stock Issued During Period, Value, New Issues | $ 4,414 |
Employee Benefit Plans Accumulated Other Comprehensive Income (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |
---|---|---|
Dec. 31, 2011
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Dec. 31, 2010
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Pension Plans, Defined Benefit [Member]
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gain (Losses), After Tax | $ 11,472 | $ 6,545 |
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Prior Service Cost Credit, After Tax | 98 | 121 |
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Tranition Assets (Obligations), After Tax | 0 | 0 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 11,570 | 6,666 |
Defined Benefit Plan, Amortization of Net Gains (Losses) | 6,560 | |
Defined Benefit Plan, Prior Service Cost (Credit) | 58 | |
Defined Benefit Plan, Transition Asset (Obligation) | 0 | |
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year | 6,618 | |
Supplemental Employee Retirement Plans, Defined Benefit [Member]
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gain (Losses), After Tax | 6,894 | 4,544 |
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Prior Service Cost Credit, After Tax | 12 | 14 |
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Tranition Assets (Obligations), After Tax | 0 | 0 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 6,906 | 4,558 |
Defined Benefit Plan, Amortization of Net Gains (Losses) | 525 | |
Defined Benefit Plan, Prior Service Cost (Credit) | 2 | |
Defined Benefit Plan, Transition Asset (Obligation) | 0 | |
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year | 527 | |
Other Postretirement Benefit Plans, Defined Benefit [Member]
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gain (Losses), After Tax | 2,556 | 2,172 |
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Prior Service Cost Credit, After Tax | (1,956) | (2,276) |
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Tranition Assets (Obligations), After Tax | 0 | 0 |
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 600 | (104) |
Defined Benefit Plan, Amortization of Net Gains (Losses) | 577 | |
Defined Benefit Plan, Prior Service Cost (Credit) | (325) | |
Defined Benefit Plan, Transition Asset (Obligation) | 0 | |
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year | $ 252 |
Business Description and Significant Accounting Policies Regulatory Assets and Liabilities (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | |
---|---|---|
Dec. 31, 2011
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Dec. 31, 2010
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | $ 242,130 | $ 204,834 |
Regulatory liabilities | 124,448 | 88,554 |
Deferred Fuel Costs [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory liabilities | 16,961 | 1,200 |
Regulatory liabilities recovery settlement period | P1Y | |
Pension Cost [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory liabilities | 59,455 | 36,155 |
Regulatory liabilities recovery settlement period | P13Y | |
Cost Of Removal [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory liabilities | 42,257 | 39,638 |
Regulatory liabilities recovery settlement period | P44Y | |
Revenue Subject to Refund [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory liabilities | 443 | 1,016 |
Regulatory liabilities recovery settlement period | P1Y | |
Other Regulatory Liabilities [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory liabilities | 5,332 | 10,545 |
Regulatory liabilities recovery settlement period | various | |
Deferred Fuel Costs [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 33,526 | 30,298 |
Regulatory assets maximum recovery settlement period | P1Y | |
Deferred Gas Cost Adjustments and Gas Price Derivatives [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 26,208 | 39,407 |
Regulatory assets maximum recovery settlement period | P1Y | |
Allowance for Cost of Equity Funds Used During Construction [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 12,482 | 13,391 |
Regulatory assets maximum recovery settlement period | P45Y | |
Employee Benefit Plans [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 120,708 | 83,144 |
Regulatory assets maximum recovery settlement period | P13Y | |
Environmental [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 1,770 | 2,353 |
Regulatory assets maximum recovery settlement period | subject to approval | |
Asset Retirement Obligation Costs [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 3,097 | 3,066 |
Regulatory assets maximum recovery settlement period | P44Y | |
Bond Issuance Costs [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 3,704 | 3,847 |
Regulatory assets maximum recovery settlement period | P25Y | |
Renewable Energy Standard Adjustment [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 20,095 | 14,254 |
Regulatory assets maximum recovery settlement period | P5Y | |
Flow Through Accounting [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | 12,191 | 7,491 |
Regulatory assets maximum recovery settlement period | P35Y | |
Other Regulatory Assets [Member]
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Schedule of Regulatory Assets and Liabilities [line items] | ||
Regulatory assets | $ 8,349 | $ 7,583 |
Regulatory assets maximum recovery settlement period | various |
Oil and Gas Reserves (Unaudited) Standard Measure of Discounted Future Net Cash Flows (Details) (USD $)
In Thousands, unless otherwise specified |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2011
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Dec. 31, 2010
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Dec. 31, 2009
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Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Future Cash Flows, Proved Oil and Gas Reserves, Standardized Measure | $ 931,637 | $ 764,585 | $ 519,867 |
Future Cash Flows, Proved Oil and Gas Reserves, Future Production Costs | (280,910) | (256,455) | (207,783) |
Future Cash Flows, Proved Oil and Gas Reserves, Future Development Costs | (92,233) | (73,805) | (34,961) |
Future Cash Flows, Proved Oil and Gas Reserves, Future Income Tax Expense | (157,922) | (111,666) | (51,287) |
Future Cash Flows, Proved Oil and Gas Reserves, Future Net Cash Flows | 400,572 | 322,659 | 225,836 |
Future Cash Flows, Proved Oil and Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows | (197,215) | (154,551) | (96,728) |
Standardized Measure of Discounted Future Net Cash Flow, Proved Oil and Gas Reserves, Period Increase (Decrease) | $ 203,357 | $ 168,108 | $ 129,108 |