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, 2015 | ||
Common stock, $1.00 par value | 44,676,072 | shares |
Page | ||||
GLOSSARY OF TERMS AND ABBREVIATIONS | ||||
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. | MINE SAFETY 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 |
AC | Alternating current |
AFUDC | Allowance for Funds Used During Construction |
AltaGas | AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd. |
AOCI | Accumulated Other Comprehensive Income |
Aquila Transaction | Our July 14, 2008 acquisition of five utilities from Aquila, Inc. |
ARO | Asset Retirement Obligations |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update as issued by the FASB |
Baseload plant | A power generation facility used to meet some or all of a given region’s continuous energy demand, producing energy at a constant rate. |
Basin Electric | Basin Electric Power Cooperative |
Bbl | Barrel |
Bcfe | Billion cubic feet equivalent |
BHC | Black Hills Corporation; the Company |
BHEP | Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, includes Black Hills Gas Resources, Inc. and Black Hills Plateau Production LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc. |
BHSC | Black Hills Service Company LLC, a direct, wholly-owned subsidiary of Black Hills Corporation |
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 |
Cheyenne Prairie | Cheyenne Prairie Generating Station is a 132 MW natural-gas fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014. |
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 |
CVA | Credit Valuation Adjustment |
DART | Days Away Restricted Transferred (number of cases with days away from work or job transfer or restrictions multiplied by 200,000 then divided by total hours worked for all employees during the year covered) |
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. These swaps were settled in November 2013. |
Dodd-Frank | Dodd-Frank Wall Street Reform and Consumer Protection Act |
DSM | Demand Side Management |
DRSPP | Dividend Reinvestment and Stock Purchase Plan |
Dth | Dekatherms |
EBITDA | Earnings before interest, taxes, depreciation and amortization, a non-GAAP measurement |
ECA | Energy Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers. |
Economy Energy | Electricity purchased by one utility from another utility to take the place of electricity that would have cost more to produce on the utility’s own system |
Enserco | Enserco Energy Inc., a formerly 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 serving Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming and 27 Tribal Nations |
EWG | Exempt Wholesale Generator |
FASB | Financial Accounting Standards Board |
FDIC | Federal Depository Insurance Corporation |
FERC | United States Federal Energy Regulatory Commission |
Fitch | Fitch Ratings |
GAAP | Accounting principles generally accepted in the United States of America |
GADS | Generation Availability Data System |
GCA | Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers. |
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 |
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. |
IEEE | Institute of Electrical and Electronics Engineers |
IFRS | International Financial Reporting Standards |
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 |
IRS | United States Internal Revenue Service |
IUB | Iowa Utilities Board |
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. |
KCC | Kansas Corporation Commission |
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 |
kV | Kilovolt |
LIBOR | London Interbank Offered Rate |
LOE | Lease Operating Expense |
Loveland Area Project | Part of the Western Area Power Association transmission system |
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 |
MGP | Manufactured Gas Plants |
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 |
N/A | Not Applicable |
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 (1 barrel equals 6 Mcfe) |
NOAA | National Oceanic and Atmospheric Administration |
NOAA Climate Normals | This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service. |
NOx | Nitrogen oxide |
NOL | Net operating loss |
NOPA | Notice of Proposed Adjustment |
NPDES | National Pollutant Discharge Elimination System |
NPSC | Nebraska Public Service Commission |
NYMEX | New York Mercantile Exchange |
OCI | Other Comprehensive Income |
OSHA | Occupational Safety & Health Administration |
OTC | Over-the-counter |
PCA | Power Cost Adjustment |
PCCA | Power Capacity Cost 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 |
Quad O Regulation | 40 CFR 60 Subpart OOOO - Standards of performance for crude oil and natural gas production, transmission and distribution |
RCRA | Resource Conservation and Recovery Act |
RICE | Reciprocating Internal Combustion Engines |
REPA | Renewable Energy Purchase Agreement |
Revolving Credit Facility | Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2019 |
RMSA | Retirement Medical Savings Account |
SAIDI | System Average Interruption Duration Index |
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. |
S&S | Significant and substantial |
Spinning Reserve | Generation capacity that is on-line but unloaded and that can respond within 10 minutes to compensate for generation or transmission outages. |
System Peak Demand | Represents the highest point of customer usage for a single hour for the system in total. Our system peaks include demand loads for 100% of plants regardless of joint ownership. |
TCA | Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case. |
TCIR | Total Case Incident Rate (average number of work-related injuries incurred by 100 workers during a one-year period) |
TIPA | Tax Increase Prevention Act of 2014 |
VEBA | Voluntary Employee Benefit Association |
VOC | Volatile Organic Compound |
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 |
WTI | West Texas Intermediate Crude |
ITEMS 1 AND 2. | BUSINESS AND PROPERTIES |
Business Group | Financial Segment |
Utilities | Electric Utilities |
Gas Utilities | |
Non-regulated Energy | Power Generation |
Coal Mining | |
Oil and Gas |
System Peak Demand (in MW) | ||||||||||
2014 | 2013 | 2012 | ||||||||
Summer | Winter | Summer | Winter | Summer | Winter | |||||
Black Hills Power | 410 | 389 | 422 | 403 | 449 | 362 | ||||
Cheyenne Light | 198 | 197 | 185 | 192 | 187 | 174 | ||||
Colorado Electric | 384 | 298 | 381 | 280 | 400 | 284 | ||||
Total Electric Utilities Peak Demands | 992 | 884 | 988 | 875 | 1,036 | 820 |
Unit | Fuel Type | Location | Ownership Interest % | Owned Capacity (MW) | Year Installed |
Black Hills Power (1): | |||||
Cheyenne Prairie (2) | Gas | Cheyenne, Wyoming | 58% | 55.0 | 2014 |
Wygen III (3) | Coal | Gillette, Wyoming | 52% | 57.2 | 2010 |
Neil Simpson II | Coal | Gillette, Wyoming | 100% | 90.0 | 1995 |
Wyodak (4) | Coal | Gillette, Wyoming | 20% | 72.4 | 1978 |
Neil Simpson CT | Gas | Gillette, Wyoming | 100% | 40.0 | 2000 |
Lange CT | Gas | Rapid City, South Dakota | 100% | 40.0 | 2002 |
Ben French Diesel #1-5 | Oil | Rapid City, South Dakota | 100% | 10.0 | 1965 |
Ben French CTs #1-4 | Gas/Oil | Rapid City, South Dakota | 100% | 80.0 | 1977-1979 |
Cheyenne Light: | |||||
Cheyenne Prairie (2) | Gas | Cheyenne, Wyoming | 42% | 40.0 | 2014 |
Cheyenne Prairie CT (2) | Gas | Cheyenne, Wyoming | 100% | 37.0 | 2014 |
Wygen II | Coal | Gillette, Wyoming | 100% | 95.0 | 2008 |
Colorado Electric: | |||||
Busch Ranch Wind Farm (5) | Wind | Pueblo, Colorado | 50% | 14.5 | 2012 |
Pueblo Airport Generation | Gas | Pueblo, Colorado | 100% | 180.0 | 2011 |
AIP Diesel | Oil | Pueblo, Colorado | 100% | 10.0 | 2001 |
Diesel #1-5 | Oil | Pueblo, Colorado | 100% | 10.0 | 1964 |
Diesel #1-5 | Oil | Rocky Ford, Colorado | 100% | 10.0 | 1964 |
Total MW Capacity | 841.1 |
(1) | The Osage, Ben French, and Neil Simpson I generating plants, having a combined capacity of 81.3 MW, were retired on March 21, 2014 due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. The remaining net book value of these plants is deferred as a Regulatory asset on the accompanying Consolidated Balance Sheets. We have requested recovery for the remaining net book values of these plants and prudent decommissioning costs of these units. The WPSC granted approval to our request in the Wyoming rate case approved in August 2014, and our request with the SDPUC is pending with a decision expected in March 2015. |
(2) | Cheyenne Prairie, a 132 MW natural gas-fired power generation facility was placed into commercial operations on October 1, 2014 to support the customers of Black Hills Power and Cheyenne Light. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Cheyenne Light and one combined-cycle, 95 MW unit that is jointly-owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW). |
(3) | 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, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our WRDC coal mine supplies all of the fuel for the plant. |
(4) | 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 supplies all of the fuel for the plant. |
(5) | Busch Ranch Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and AltaGas owns the remaining 50%. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 MW of power from the wind farm. The wind farm became operational October 16, 2012. |
Fuel Source (dollars per megawatt-hour) | 2014 | 2013 | 2012 | ||||||
Coal | $ | 10.92 | $ | 10.89 | $ | 14.42 | |||
Natural Gas | $ | 77.31 | $ | 53.53 | $ | 52.08 | |||
Diesel Oil | $ | 174.04 | $ | 233.47 | $ | 280.29 | |||
Total Average Fuel Cost | $ | 14.82 | $ | 14.65 | $ | 16.05 | |||
Purchased Power - Coal, Gas and Oil | $ | 35.21 | $ | 29.95 | $ | 26.70 | |||
Purchased Power - Renewable Sources | $ | 50.27 | $ | 49.20 | $ | 47.45 |
Power Supply | 2014 | 2013 | 2012 | |||
Coal | 34 | % | 36 | % | 37 | % |
Gas, Oil and Wind | 4 | 4 | 2 | |||
Total Generated | 38 | 40 | 39 | |||
Purchased | 62 | 60 | 61 | |||
Total | 100 | % | 100 | % | 100 | % |
• | Black Hills Power’s PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase of 50 MW of coal-fired baseload power; |
• | Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, which provides 200 MW of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease on the accompanying Consolidated Financial Statements; |
• | Colorado Electric’s PPA with Cargill expiring on December 31, 2015, which provides for the purchase of 50 MW of energy during heavy load timing intervals; |
• | Colorado Electric’s PPA with Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW of energy during light load timing intervals; |
• | Colorado Electric’s PPA with AltaGas expiring on October 16, 2037, which provides up to 14.5 MW of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Project; |
• | Cheyenne Light’s PPA with Black Hills Wyoming expiring on 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 through 2019. The purchase price related to the option is $2.6 million per MW adjusted for capital additions and reduced by depreciation over a 35-year life beginning January 1, 2009 (approximately $5 million per year); |
• | Cheyenne Light’s 20-year PPA with Duke Energy expiring on September 3, 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50% of the facility’s output to Black Hills Power; |
• | Cheyenne Light’s 20-year PPA with Duke Energy expiring on September 30, 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 MW of energy from Silver Sage to Black Hills Power; and |
• | Cheyenne Light and Black Hills Power’s Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light’s excess energy. |
• | MDU owns a 25% 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 its other generation facilities or from system purchases with reimbursement of costs by MDU; |
• | Black Hills Power has an agreement through December 31, 2023 to serve MDU capacity and energy up to a maximum of 50 MW. |
• | The City of Gillette owns a 23% 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 its 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 its 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 purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: |
2015-2017 | 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; and |
• | 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. |
Utility | State | Transmission (in Line Miles) | Distribution (in Line Miles) | ||
Black Hills Power | South Dakota, Wyoming | 1,182 | 2,474 | ||
Black Hills Power - Jointly Owned (1) | South Dakota, Wyoming | 44 | — | ||
Cheyenne Light | South Dakota, Wyoming | 48 | 1,257 | ||
Colorado Electric | Colorado | 585 | 3,070 |
(1) | Black Hills Power owns 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. |
• | Shared Services Agreements - |
◦ | Black Hills Power, Cheyenne Light, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets by the affiliate entity. |
◦ | Black Hills Colorado IPP and Colorado Electric are also parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric assets. |
◦ | Black Hills Power and Cheyenne Light also receive certain staffing and management services from BHSC for Cheyenne Prairie. |
• | Jointly Owned Facilities - |
◦ | Black Hills Power, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby Black Hills Power charges the City of Gillette and MDU for administrative services, plant operations and maintenance for their share of the Wygen III generating facility for the life of the plant. |
◦ | Colorado Electric and AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric charges AltaGas for operations and maintenance for their share of the Busch Ranch Wind Farm. |
Degree Days | 2014 | 2013 | 2012 | ||||||
Actual | Variance from 30-Year Average (b) | Actual | Variance from 30-Year Average (b) | Actual | Variance from 30-Year Average (b) | ||||
Heating Degree Days: | |||||||||
Black Hills Power | 7,373 | 4% | 7,582 | 9% | 6,206 | (13)% | |||
Cheyenne Light | 7,100 | —% | 7,386 | 4% | 6,304 | (11)% | |||
Colorado Electric | 5,534 | —% | 5,740 | 1% | 4,921 | (13)% | |||
Combined (a) | 6,473 | 2% | 6,691 | 5% | 5,629 | (12)% | |||
Cooling Degree Days: | |||||||||
Black Hills Power | 481 | (28)% | 724 | 8% | 937 | 47% | |||
Cheyenne Light | 336 | (5)% | 520 | 48% | 568 | 63% | |||
Colorado Electric | 919 | (4)% | 1,230 | 28% | 1,322 | 47% | |||
Combined (a) | 654 | (12)% | 918 | 7% | 1,043 | 47% |
(b) | 30-Year Average is from NOAA Climate Normals. |
Revenue - Electric (in thousands) | 2014 | 2013 | 2012 | ||||||
Residential: | |||||||||
Black Hills Power | $ | 69,712 | $ | 64,566 | $ | 58,523 | |||
Cheyenne Light | 36,634 | 35,778 | 32,053 | ||||||
Colorado Electric (a) | 94,391 | 95,631 | 91,550 | ||||||
Total Residential | 200,737 | 195,975 | 182,126 | ||||||
Commercial: | |||||||||
Black Hills Power | 91,882 | 80,289 | 73,858 | ||||||
Cheyenne Light | 59,758 | 57,444 | 55,600 | ||||||
Colorado Electric | 90,909 | 87,732 | 82,849 | ||||||
Total Commercial | 242,549 | 225,465 | 212,307 | ||||||
Industrial: | |||||||||
Black Hills Power | 28,451 | 27,705 | 25,656 | ||||||
Cheyenne Light | 29,066 | 20,803 | 16,105 | ||||||
Colorado Electric | 39,219 | 38,037 | 37,540 | ||||||
Total Industrial | 96,736 | 86,545 | 79,301 | ||||||
Municipal: | |||||||||
Black Hills Power | 3,409 | 3,421 | 3,268 | ||||||
Cheyenne Light | 1,930 | 1,918 | 1,807 | ||||||
Colorado Electric | 13,312 | 13,106 | 13,373 | ||||||
Total Municipal | 18,651 | 18,445 | 18,448 | ||||||
Subtotal Retail Revenue - Electric | 558,673 | 526,430 | 492,182 | ||||||
Contract Wholesale: | |||||||||
Total Contract Wholesale - Black Hills Power | 21,206 | 21,956 | 20,290 | ||||||
Off-system/Power Marketing Wholesale: | |||||||||
Black Hills Power | 28,002 | 29,580 | 31,905 | ||||||
Cheyenne Light | 8,179 | 8,712 | 8,365 | ||||||
Colorado Electric | 5,726 | 8,329 | 6,003 | ||||||
Total Off-system/Power Marketing Wholesale | 41,907 | 46,621 | 46,273 | ||||||
Other Revenue: (b) | |||||||||
Black Hills Power | 25,826 | 26,510 | 29,809 | ||||||
Cheyenne Light | 2,253 | 1,916 | 2,336 | ||||||
Colorado Electric (c) | 7,691 | 4,612 | 4,652 | ||||||
Total Other Revenue | 35,770 | 33,038 | 36,797 | ||||||
Total Revenue - Electric | $ | 657,556 | $ | 628,045 | $ | 595,542 |
(a) | 2013 includes $0.7 million and 2012 includes $2.1 million in construction savings incentives from the construction of the Pueblo Airport Generating Station. |
(b) | Other revenue primarily consists of transmission revenue. |
(c) | Increase in 2014 is primarily due to $1.8 million in technical service revenues for facility improvements at one of our large industrial customers. |
Quantities Generated and Purchased (MWh) | 2014 | 2013 | 2012 | |||
Generated - | ||||||
Coal-fired: | ||||||
Black Hills Power (a) | 1,591,061 | 1,768,483 | 1,796,936 | |||
Cheyenne Light | 697,220 | 688,318 | 587,832 | |||
Colorado Electric (b) | — | — | 222,647 | |||
Total Coal - fired | 2,288,281 | 2,456,801 | 2,607,415 | |||
Natural Gas and Oil: | ||||||
Black Hills Power (c) | 44,984 | 33,374 | 33,183 | |||
Cheyenne Light (c) | 12,534 | — | — | |||
Colorado Electric (d) | 140,942 | 247,758 | 84,874 | |||
Total Natural Gas and Oil | 198,460 | 281,132 | 118,057 | |||
Wind: | ||||||
Colorado Electric | 48,318 | 45,765 | 12,433 | |||
Total Wind | 48,318 | 45,765 | 12,433 | |||
Total Generated: | ||||||
Black Hills Power | 1,636,045 | 1,801,857 | 1,830,119 | |||
Cheyenne Light | 709,754 | 688,318 | 587,832 | |||
Colorado Electric | 189,260 | 293,523 | 319,954 | |||
Total Generated | 2,535,059 | 2,783,698 | 2,737,905 | |||
Purchased - | ||||||
Black Hills Power | 1,446,630 | 1,441,286 | 1,678,090 | |||
Cheyenne Light | 766,475 | 779,677 | 807,659 | |||
Colorado Electric | 1,898,232 | 1,886,627 | 1,794,229 | |||
Total Purchased (e) | 4,111,337 | 4,107,590 | 4,279,978 | |||
Total Generated and Purchased | 6,646,396 | 6,891,288 | 7,017,883 |
(a) | Neil Simpson I was retired on March 21, 2014. |
(b) | W.N. Clark suspended operations in 2012. |
(c) | Cheyenne Prairie was placed into commercial service on October 1, 2014. |
(d) | Decrease in 2014 generation primarily due to increased commodity prices that impacted power marketing sales. |
(e) | Includes wind power of 224,229 MWh, 222,069 MWh, and 199,079 MWh in 2014, 2013 and 2012, respectively. |
Quantities (MWh) | 2014 | 2013 | 2012 | |||
Residential: | ||||||
Black Hills Power | 542,008 | 555,204 | 532,342 | |||
Cheyenne Light | 261,038 | 272,490 | 261,792 | |||
Colorado Electric | 598,872 | 619,857 | 614,521 | |||
Total Residential | 1,401,918 | 1,447,551 | 1,408,655 | |||
Commercial: | ||||||
Black Hills Power | 782,238 | 730,701 | 731,785 | |||
Cheyenne Light | 528,689 | 544,636 | 577,141 | |||
Colorado Electric | 685,094 | 703,604 | 723,216 | |||
Total Commercial | 1,996,021 | 1,978,941 | 2,032,142 | |||
Industrial: | ||||||
Black Hills Power | 399,648 | 404,009 | 407,301 | |||
Cheyenne Light | 382,306 | 281,727 | 224,448 | |||
Colorado Electric | 432,167 | 371,102 | 358,490 | |||
Total Industrial | 1,214,121 | 1,056,838 | 990,239 | |||
Municipal: | ||||||
Black Hills Power | 32,076 | 34,344 | 35,933 | |||
Cheyenne Light | 9,425 | 9,848 | 9,631 | |||
Colorado Electric | 122,247 | 114,732 | 121,480 | |||
Total Municipal | 163,748 | 158,924 | 167,044 | |||
Subtotal Retail Quantity Sold | 4,775,808 | 4,642,254 | 4,598,080 | |||
Contract Wholesale: | ||||||
Total Contract Wholesale - Black Hills Power | 340,871 | 357,193 | 340,036 | |||
Off-system Wholesale: | ||||||
Black Hills Power | 808,257 | 1,002,847 | 1,263,457 | |||
Cheyenne Light | 191,069 | 234,566 | 229,062 | |||
Colorado Electric | 119,315 | 219,349 | 160,430 | |||
Total Off-system Wholesale | 1,118,641 | 1,456,762 | 1,652,949 | |||
Total Quantity Sold: | ||||||
Black Hills Power | 2,905,098 | 3,084,298 | 3,310,854 | |||
Cheyenne Light | 1,372,527 | 1,343,267 | 1,302,074 | |||
Colorado Electric | 1,957,695 | 2,028,644 | 1,978,137 | |||
Total Quantity Sold | 6,235,320 | 6,456,209 | 6,591,065 | |||
Other Uses, Losses or Generation, net (a): | ||||||
Black Hills Power | 177,577 | 158,845 | 197,355 | |||
Cheyenne Light | 103,702 | 124,728 | 93,417 | |||
Colorado Electric | 129,797 | 151,506 | 136,046 | |||
Total Other Uses, Losses and Generation, net | 411,076 | 435,079 | 426,818 | |||
Total Energy | 6,646,396 | 6,891,288 | 7,017,883 |
(a) | Includes company uses, line losses, test energy and excess exchange production. |
Customers at End of Year | 2014 | 2013 | 2012 | |||
Residential: | ||||||
Black Hills Power | 56,511 | 55,840 | 55,296 | |||
Cheyenne Light | 36,253 | 35,780 | 35,438 | |||
Colorado Electric | 82,710 | 82,371 | 81,795 | |||
Total Residential | 175,474 | 173,991 | 172,529 | |||
Commercial: | ||||||
Black Hills Power (a) | 13,173 | 12,888 | 12,857 | |||
Cheyenne Light | 4,489 | 4,471 | 4,276 | |||
Colorado Electric | 11,156 | 11,060 | 11,220 | |||
Total Commercial | 28,818 | 28,419 | 28,353 | |||
Industrial: | ||||||
Black Hills Power (a) | 23 | 46 | 44 | |||
Cheyenne Light | 4 | 3 | 2 | |||
Colorado Electric | 66 | 61 | 61 | |||
Total Industrial | 93 | 110 | 107 | |||
Other Electric Customers: | ||||||
Black Hills Power | 325 | 310 | 308 | |||
Cheyenne Light | 224 | 232 | 240 | |||
Colorado Electric | 469 | 469 | 475 | |||
Total Other Electric Customers | 1,018 | 1,011 | 1,023 | |||
Subtotal Retail Customers | 205,403 | 203,531 | 202,012 | |||
Contract Wholesale: | ||||||
Total Contract Wholesale - Black Hills Power | 3 | 3 | 3 | |||
Total Customers: | ||||||
Black Hills Power | 70,035 | 69,087 | 68,508 | |||
Cheyenne Light | 40,970 | 40,486 | 39,956 | |||
Colorado Electric | 94,401 | 93,961 | 93,551 | |||
Total Electric Customers at End of Year | 205,406 | 203,534 | 202,015 |
(a) | Change in customers is due to classification change to Commercial billing in 2014 based on customer’s business type. |
2014 | 2013 | 2012 | |||||||
Revenue - Gas (in thousands): | |||||||||
Residential | $ | 24,426 | $ | 23,047 | $ | 19,327 | |||
Commercial | 11,279 | 10,326 | 8,613 | ||||||
Industrial | 2,945 | 3,050 | 2,715 | ||||||
Other Sales Revenue | 1,104 | 840 | 769 | ||||||
Total Revenue - Gas | $ | 39,754 | $ | 37,263 | $ | 31,424 | |||
Gross Margin - Gas (in thousands): | |||||||||
Residential | $ | 11,615 | $ | 12,706 | $ | 10,712 | |||
Commercial | 3,582 | 3,993 | 2,963 | ||||||
Industrial | 525 | 598 | 551 | ||||||
Other Gross Margin | 1,104 | 881 | 766 | ||||||
Total Gross Margin - Gas | $ | 16,826 | $ | 18,178 | $ | 14,992 | |||
Quantities Sold (Dth): | |||||||||
Residential | 2,515,243 | 2,728,797 | 2,215,858 | ||||||
Commercial | 1,482,904 | 1,653,021 | 1,447,522 | ||||||
Industrial | 539,848 | 652,539 | 598,408 | ||||||
Total Quantities Sold | 4,537,995 | 5,034,357 | 4,261,788 | ||||||
Gas Customers at Year-End | 36,033 | 35,494 | 35,021 |
System Infrastructure (in line miles) as of | Intrastate Gas Transmission Pipelines | Gas Distribution Mains | Gas Distribution Service Lines | |||
December 31, 2014 | ||||||
Colorado | 126 | 3,030 | 942 | |||
Nebraska | 44 | 3,482 | 2,474 | |||
Iowa | 182 | 2,690 | 2,373 | |||
Kansas | 293 | 2,755 | 1,312 | |||
Total | 645 | 11,957 | 7,101 |
2014 | 2013 | 2012 | |||||||||
Actual | Variance From 30-Year Average (c) | Actual | Variance From 30-Year Average (c) | Actual | Variance From 30-Year Average (c) | ||||||
Heating Degree Days: | |||||||||||
Colorado | 6,108 | (3)% | 6,310 | 1% | 5,186 | (18)% | |||||
Nebraska | 6,193 | 2% | 6,516 | 8% | 5,198 | (15)% | |||||
Iowa | 7,875 | 16% | 7,743 | 14% | 6,093 | (10)% | |||||
Kansas (a) | 5,099 | 4% | 5,294 | 8% | 4,190 | (15)% | |||||
Combined (b) | 6,780 | 7% | 6,922 | 9% | 5,518 | (13)% |
(a) | Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins. |
(b) | The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. |
(c) | 30-Year Average is from NOAA climate normals. |
Revenue (in thousands) | 2014 | 2013 | 2012 | ||||||
Residential: | |||||||||
Colorado | $ | 58,439 | $ | 53,296 | $ | 48,406 | |||
Nebraska | 135,052 | 122,197 | 98,339 | ||||||
Iowa | 124,145 | 98,498 | 82,669 | ||||||
Kansas | 74,128 | 67,501 | 55,096 | ||||||
Total Residential | 391,764 | 341,492 | 284,510 | ||||||
Commercial: | |||||||||
Colorado | 12,233 | 10,515 | 9,558 | ||||||
Nebraska | 39,947 | 37,190 | 30,894 | ||||||
Iowa | 60,640 | 47,494 | 36,550 | ||||||
Kansas | 24,966 | 21,440 | 15,677 | ||||||
Total Commercial | 137,786 | 116,639 | 92,679 | ||||||
Industrial: | |||||||||
Colorado | 1,909 | 1,661 | 1,963 | ||||||
Nebraska | 830 | 900 | 876 | ||||||
Iowa | 4,386 | 3,436 | 2,458 | ||||||
Kansas | 16,963 | 15,753 | 13,614 | ||||||
Total Industrial | 24,088 | 21,750 | 18,911 | ||||||
Other: | |||||||||
Colorado | 118 | (17 | ) | 181 | |||||
Nebraska | 2,440 | 2,265 | 2,066 | ||||||
Iowa | 724 | 543 | 452 | ||||||
Kansas | 2,836 | 2,326 | 5,124 | ||||||
Total Other Sales Revenue | 6,118 | 5,117 | 7,823 | ||||||
Distribution: | |||||||||
Colorado | 72,699 | 65,455 | 60,108 | ||||||
Nebraska | 178,269 | 162,552 | 132,175 | ||||||
Iowa | 189,895 | 149,971 | 122,129 | ||||||
Kansas | 118,893 | 107,020 | 89,511 | ||||||
Total Distribution | 559,756 | 484,998 | 403,923 | ||||||
Transportation: | |||||||||
Colorado | 968 | 1,033 | 866 | ||||||
Nebraska | 14,272 | 12,943 | 10,589 | ||||||
Iowa | 4,934 | 4,809 | 4,128 | ||||||
Kansas | 7,448 | 6,472 | 5,762 | ||||||
Total Transportation | 27,622 | 25,257 | 21,345 | ||||||
Total Regulated Revenue | 587,378 | 510,255 | 425,268 | ||||||
Non-regulated Services | 30,390 | 29,434 | 28,813 | ||||||
Total Revenue | $ | 617,768 | $ | 539,689 | $ | 454,081 |
Gross Margin (in thousands) | 2014 | 2013 | 2012 | ||||||
Residential: | |||||||||
Colorado | $ | 18,100 | $ | 18,244 | $ | 16,400 | |||
Nebraska | 54,996 | 53,367 | 46,982 | ||||||
Iowa | 44,134 | 42,961 | 39,561 | ||||||
Kansas | 32,809 | 32,111 | 28,734 | ||||||
Total Residential | 150,039 | 146,683 | 131,677 | ||||||
Commercial: | |||||||||
Colorado | 3,048 | 3,009 | 2,680 | ||||||
Nebraska | 11,708 | 11,560 | 10,201 | ||||||
Iowa | 13,206 | 13,060 | 11,071 | ||||||
Kansas | 8,115 | 7,436 | 6,097 | ||||||
Total Commercial | 36,077 | 35,065 | 30,049 | ||||||
Industrial: | |||||||||
Colorado | 464 | 519 | 581 | ||||||
Nebraska | 239 | 250 | 249 | ||||||
Iowa | 294 | 321 | 257 | ||||||
Kansas | 2,336 | 2,220 | 2,362 | ||||||
Total Industrial | 3,333 | 3,310 | 3,449 | ||||||
Other: | |||||||||
Colorado | 118 | (17 | ) | 181 | |||||
Nebraska | 2,441 | 2,266 | 2,066 | ||||||
Iowa | 724 | 543 | 452 | ||||||
Kansas | 1,990 | 1,723 | 4,787 | ||||||
Total Other Sales Margins | 5,273 | 4,515 | 7,486 | ||||||
Distribution: | |||||||||
Colorado | 21,730 | 21,755 | 19,842 | ||||||
Nebraska | 69,384 | 67,443 | 59,498 | ||||||
Iowa | 58,358 | 56,885 | 51,341 | ||||||
Kansas | 45,250 | 43,490 | 41,980 | ||||||
Total Distribution | 194,722 | 189,573 | 172,661 | ||||||
Transportation: | |||||||||
Colorado | 968 | 1,033 | 866 | ||||||
Nebraska | 14,272 | 12,943 | 10,589 | ||||||
Iowa | 4,934 | 4,809 | 4,128 | ||||||
Kansas | 7,448 | 6,472 | 5,762 | ||||||
Total Transportation | 27,622 | 25,257 | 21,345 | ||||||
Total Regulated Gross Margin: | |||||||||
Colorado | 22,698 | 22,788 | 20,708 | ||||||
Nebraska | 83,656 | 80,386 | 70,087 | ||||||
Iowa | 63,292 | 61,694 | 55,469 | ||||||
Kansas | 52,698 | 49,962 | 47,742 | ||||||
Total Regulated Gross Margin | 222,344 | 214,830 | 194,006 | ||||||
Non-regulated Services | 14,572 | 14,396 | 14,726 | ||||||
Total Gross Margin | $ | 236,916 | $ | 229,226 | $ | 208,732 |
Distribution Quantities Sold and Transportation (in Dth) | 2014 | 2013 | 2012 | |||
Residential: | ||||||
Colorado | 6,718,508 | 6,969,741 | 5,869,817 | |||
Nebraska | 13,068,132 | 12,717,565 | 9,555,073 | |||
Iowa | 12,172,281 | 11,359,220 | 8,732,301 | |||
Kansas | 7,313,273 | 7,174,085 | 5,681,199 | |||
Total Residential | 39,272,194 | 38,220,611 | 29,838,390 | |||
Commercial: | ||||||
Colorado | 1,537,704 | 1,506,227 | 1,284,082 | |||
Nebraska | 4,644,645 | 4,770,370 | 3,952,067 | |||
Iowa | 7,182,173 | 7,056,978 | 5,304,162 | |||
Kansas | 3,043,685 | 2,867,696 | 2,121,063 | |||
Total Commercial | 16,408,207 | 16,201,271 | 12,661,374 | |||
Industrial: | ||||||
Colorado | 354,630 | 405,047 | 463,566 | |||
Nebraska | 122,662 | 150,227 | 158,445 | |||
Iowa | 630,912 | 648,173 | 492,633 | |||
Kansas | 3,384,797 | 3,355,930 | 3,675,678 | |||
Total Industrial | 4,493,001 | 4,559,377 | 4,790,322 | |||
Wholesale and Other: | ||||||
Kansas | 150,014 | 116,234 | 68,419 | |||
Total Wholesale and Other | 150,014 | 116,234 | 68,419 | |||
Distribution Quantities Sold: | ||||||
Colorado | 8,610,842 | 8,881,015 | 7,617,465 | |||
Nebraska | 17,835,439 | 17,638,162 | 13,665,585 | |||
Iowa | 19,985,366 | 19,064,371 | 14,529,096 | |||
Kansas | 13,891,769 | 13,513,945 | 11,546,359 | |||
Total Distribution Quantities Sold | 60,323,416 | 59,097,493 | 47,358,505 | |||
Transportation: | ||||||
Colorado | 950,819 | 1,015,791 | 850,156 | |||
Nebraska | 30,669,764 | 28,171,610 | 26,649,759 | |||
Iowa | 19,959,462 | 20,176,525 | 18,294,228 | |||
Kansas | 15,883,098 | 14,457,620 | 14,686,679 | |||
Total Transportation | 67,463,143 | 63,821,546 | 60,480,822 | |||
Total Distribution Quantities Sold and Transportation: | ||||||
Colorado | 9,561,661 | 9,896,806 | 8,467,621 | |||
Nebraska | 48,505,203 | 45,809,772 | 40,315,344 | |||
Iowa | 39,944,828 | 39,240,896 | 32,823,324 | |||
Kansas | 29,774,867 | 27,971,565 | 26,233,038 | |||
Total Distribution Quantities Sold and Transportation | 127,786,559 | 122,919,039 | 107,839,327 |
Customers at End of Year | 2014 | 2013 | 2012 | |||
Residential: | ||||||
Colorado | 72,360 | 70,410 | 68,927 | |||
Nebraska | 180,014 | 178,389 | 176,953 | |||
Iowa | 138,503 | 137,525 | 135,897 | |||
Kansas | 99,359 | 99,315 | 98,516 | |||
Total Residential | 490,236 | 485,639 | 480,293 | |||
Commercial: | ||||||
Colorado | 3,788 | 3,737 | 3,681 | |||
Nebraska | 15,900 | 15,739 | 15,626 | |||
Iowa | 15,303 | 15,418 | 15,398 | |||
Kansas | 10,547 | 9,832 | 9,584 | |||
Total Commercial | 45,538 | 44,726 | 44,289 | |||
Industrial: | ||||||
Colorado | 205 | 207 | 213 | |||
Nebraska | 147 | 136 | 136 | |||
Iowa | 90 | 94 | 94 | |||
Kansas | 1,277 | 1,358 | 1,261 | |||
Total Industrial | 1,719 | 1,795 | 1,704 | |||
Transportation: | ||||||
Colorado | 34 | 36 | 36 | |||
Nebraska | 4,151 | 4,240 | 4,115 | |||
Iowa | 418 | 421 | 412 | |||
Kansas | 1,145 | 1,171 | 1,166 | |||
Total Transportation | 5,748 | 5,868 | 5,729 | |||
Wholesale: | ||||||
Kansas | 8 | 7 | 7 | |||
Total Wholesale | 8 | 7 | 7 | |||
Total Customers: | ||||||
Colorado | 76,387 | 74,390 | 72,857 | |||
Nebraska | 200,212 | 198,504 | 196,830 | |||
Iowa | 154,314 | 153,458 | 151,801 | |||
Kansas | 112,336 | 111,683 | 110,534 | |||
Total Customers at End of Year | 543,249 | 538,035 | 532,022 |
Subsidiary | Jurisdic-tion | Authorized Rate of Return on Equity | Authorized Return on Rate Base | Capital Structure Debt/Equity | Authorized Rate Base (in millions) | Effective Date | Tariff and Rate Matters | Percentage of Power Marketing Activity Shared with Customers |
Electric Utilities: | ||||||||
Black Hills Power | WY | 9.9% | 8.13% | 46.7%/53.3% | $46.8 | 10/2014 | ECA | 65% |
SD | Global Settlement | 7.93% | Global Settlement | $440.2 | 6/2013 | ECA, TCA, Energy Efficiency Cost Recovery/DSM | 65% | |
SD | 8.16% | 6/2011 | Environmental Improvement Cost Recovery Adjustment Tariff | N/A | ||||
MT | 15.0% | 11.7% | 47%/53% | 1983 | ECA | N/A | ||
FERC | 10.8% | 9.1% | 43%/57% | 2/2009 | FERC Transmission Tariff | N/A | ||
Cheyenne Light - Electric | WY | 9.9% | 7.98% | 46%/54% | $376.8 | 10/2014 | PCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment | N/A |
FERC | 10.6% | 8.51% | 46%/54% | $31.5 | 5/2014 | FERC Transmission Tariff | N/A | |
Cheyenne Light - Gas | WY | 9.9% | 7.98% | 46%/54% | $59.6 | 10/2014 | GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment | N/A |
Colorado Electric | CO | 9.83% | 7.55% | 50.2%/49.8% | $448.3 | 1/2015 | ECA, TCA, PCCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment, Construction Rider | 90% |
Gas Utilities: | ||||||||
Colorado Gas | CO | 9.6% | 8.4% | 50%/50% | $64.0 | 12/2012 | GCA, Energy Efficiency Cost Recovery/DSM | N/A |
Nebraska Gas | NE | 10.1% | 9.1% | 48%/52% | $161.0 | 9/2010 | GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge | N/A |
Kansas Gas | KS | Global Settlement | Global Settlement | Global Settlement | $127.4 | 1/2015 | GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA | N/A |
Iowa Gas | IA | Global Settlement | Global Settlement | Global Settlement | $110.2 | 2/2011 | GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism | N/A |
• | In Wyoming, Cheyenne Light has an annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. Until October 1, 2014, at Cheyenne Light, our pass-through sharing mechanism relating to transmission and the PCA, returned 85% to the customer, and the Company retained 15%. Effective October 1, 2014, coal and coal related costs are passed through under an 85% / 15% distribution methodology, and purchased power costs, transmission, and natural gas costs are passed through under a 95% / 5% distribution methodology. |
• | In South Dakota, Black Hills Power has an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power cost incurred to serve South Dakota customers. Additionally, the ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 65% of off-system power marketing operating income. The modification also adjusts the methodology to directly assign renewable resources and firm purchases to the customer load. In Wyoming a similar fuel and purchased power cost adjustment is also in place. |
• | In South Dakota, we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011, which recovers costs associated with generation plant environmental improvements. |
• | We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of Black Hills Power’s open access transmission tariff. |
• | We have an approved FERC Transmission Tariff that determines the revenue component of Cheyenne Light’s open access transmission tariff. |
• | In Colorado, we have a quarterly ECA rider (the rider was semi-annual until August 1, 2013) that allows us to recover forecasted increases or decreases in purchased energy and fuel costs, including the recovery for amounts payable to others for the transmission of the utility's electricity over transmission facilities owned by others, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs (customer receives 90%). Through 2013, this sharing percentage allowed 75% to the customers. The ECA provides for not only direct recovery, but also for the issuance of credits for decreases in purchased energy, fuel costs and eligible energy resources. Additionally, Colorado allows an annual TCA rider, that includes nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism. |
• | On December 19, 2014, Colorado Electric received approval from the CPUC to implement a rider effective January 1, 2015 to recover a return on the construction costs of a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant. |
• | In Kansas, we have a tariff pass-through mechanism for weather normalization, as well as tariffs that provide timely recovery of certain capital expenditures and property tax fluctuations. |
• | In Kansas and Nebraska, we are allowed to recover the portion of uncollectible accounts related to gas costs through GCAs. |
• | In Iowa, we have a Capital Infrastructure Automatic Adjustment Mechanism that allows for recovery of certain capital infrastructure investments. |
• | In Nebraska, we have an Infrastructure System Replacement Cost mechanism that allows for recovery of certain capital infrastructure investments. |
Type of Service | Date Requested | Effective Date | Revenue Amount Requested | Revenue Amount Approved | |||||
Cheyenne Light (a) | Electric/Gas | 12/2013 | 10/2014 | $ | 14.1 | $ | 9.2 | ||
Black Hills Power (b) | Electric | 1/2014 | 10/2014 | $ | 2.8 | $ | 2.2 | ||
Black Hills Power (c) | Electric | 3/2014 | 10/2014 | $ | 14.6 | pending | |||
Iowa Gas (d) | Gas | 2/2014 | 4/2014 | $ | 0.5 | $ | 0.5 | ||
Kansas Gas (e) | Gas | 4/2014 | 1/2015 | $ | 7.3 | $ | 5.2 | ||
Colorado Electric (f) | Electric | 4/2014 | 1/2015 | $ | 4.0 | $ | 3.1 |
(a) | On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 54% equity and 46% debt. The WPSC’s decision provides Cheyenne Light a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas-fired facility. |
(b) | On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt. The WPSC’s decision provides Black Hills Power a return on its investment in Cheyenne Prairie and associated infrastructure and provides recovery of its share of operating expenses for this natural gas-fired facility. |
(c) | On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. We expect a final decision from the SDPUC on our rate request by the end of the first quarter of 2015. Interim rates will be trued up as necessary based on the final approval. |
(d) | On April 15, 2014, the IUB approved a capital investment recovery surcharge increase of $0.5 million. |
(e) | On April 29, 2014, Kansas Gas filed a rate request with the KCC to increase annual revenue to recover infrastructure and increased operating costs. On October 24, 2014, a settlement agreement was reached between Kansas Gas, the KCC and intervenors to increase base rates by $5.2 million. On December 16, 2014, Kansas Gas received approval from the KCC to increase base rates by $5.2 million. |
(f) | On April 30, 2014, Colorado Electric filed a rate request with the CPUC to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The filing also requested to implement a rider to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant. On December 19, 2014, Colorado Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of the rider. |
• | Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% retail rate impact for compliance with the electric resource standards. The electric resource standards require our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 20% of retail sales from 2015 to 2019; and (ii) 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 net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) is limited to 2%. The standard 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. On May 5, 2014, Colorado Electric issued an all-source generation request for approximately 42 MW of summer seasonal firm capacity in 2017, 2018 and 2019 and up to 60 MW of eligible renewable energy resources to serve its customers in southern Colorado. Colorado IPP submitted solar and wind bids in response to this request. On December 23, 2014, the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that Colorado IPP’s bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration. |
• | Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, Black Hills Power filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. In March 2013, the Montana Legislature adopted legislation that had the effect of excluding Black Hills Power from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers we have in Montana and the relatively high cost of meeting the renewable requirements. |
• | 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. |
• | Wyoming. Wyoming currently has no renewable energy portfolio standard. |
Environmental Expenditure Estimates | Total (in millions) | ||
2015 | $ | 2.9 | |
2016 | 3.5 | ||
2017 | 1.9 | ||
Total | $ | 8.3 |
Plant | Company | MW | Type of Plant | Date Suspended | Actual Retirement Date | Age of Plant (in years) | |||
Osage | Black Hills Power | 34.5 | Coal | October 1, 2010 | March 21, 2014 | 64 | |||
Ben French | Black Hills Power | 25.0 | Coal | August 31, 2012 | March 21, 2014 | 52 | |||
Neil Simpson I | Black Hills Power | 21.8 | Coal | NA | March 21, 2014 | 43 | |||
W.N. Clark | Colorado Electric | 42.0 | Coal | December 31, 2012 | December 31, 2013 | 57 | |||
Pueblo Unit #5 | Colorado Electric | 9.0 | Gas | December 31, 2012 | December 31, 2013 | 71 | |||
Pueblo Unit #6 | Colorado Electric | 20.0 | Gas | December 31, 2012 | December 31. 2013 | 63 | |||
Total MW | 152.3 |