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 |