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 | 7001 Mount Rushmore Road | IRS Identification Number |
Rapid City, South Dakota 57702 | 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 | |||
Emerging growth company o | ||||
Class | Outstanding at January 31, 2019 | ||
Common stock, $1.00 par value | 60,003,965 | 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 | ||
Part IV | |||
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | ||
ITEM 16. | FORM 10-K SUMMARY | ||
SIGNATURES |
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. |
APSC | Arkansas Public Service Commission |
Arkansas Gas | Includes the acquired SourceGas utility Black Hills Energy Arkansas, Inc. utility operations (doing business as Black Hills Energy) |
ARO | Asset Retirement Obligations |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update as issued by the FASB |
ATM | At-the-market equity offering program |
Basin Electric | Basin Electric Power Cooperative |
Bbl | Barrel |
Bcf | Billion cubic feet |
BHC | Black Hills Corporation; the Company |
BHEP | Black Hills Exploration and Production, Inc., our previous Oil and Gas segment. As of December 31, 2018, we have completed the exit of the Oil and Gas business. |
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 50.1% owned subsidiary of Black Hills Electric Generation |
Black Hills Gas | Black Hills Gas, LLC, a subsidiary of Black Hills Gas Holdings, which was previously named SourceGas LLC. |
Black Hills Gas Holdings | Black Hills Gas Holdings, LLC, a subsidiary of Black Hills Utility Holdings, which was previously named SourceGas Holdings LLC |
Black Hills Electric Generation | Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
Black Hills Energy | The name used to conduct the business of our utility companies |
Black Hills Energy Colorado Electric | Includes Colorado Electric’s utility operations |
Black Hills Energy Colorado Gas | Includes Black Hills Energy Colorado Gas utility operations, as well as RMNG |
Black Hills Energy Iowa Gas | Includes Black Hills Energy Iowa gas utility operations |
Black Hills Energy Kansas Gas | Includes Black Hills Energy Kansas gas utility operations |
Black Hills Energy Nebraska Gas | Includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska gas operations |
Black Hills Energy Services | A Choice Gas supplier acquired in the SourceGas Acquisition |
Black Hills Energy South Dakota Electric | Includes Black Hills Power’s operations in South Dakota, Wyoming and Montana |
Black Hills Energy Wyoming Electric | Includes Cheyenne Light’s electric utility operations |
Black Hills Energy Wyoming Gas | Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations |
Black Hills Gas Distribution | Black Hills Gas Distribution, LLC, a company acquired in the SourceGas Acquisition that conducts the gas distribution operations in Nebraska and Wyoming. It was formerly named SourceGas Distribution LLC. |
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 (doing business as Black Hills Energy) |
Black Hills Utility Holdings | Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy) |
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 |
Busch Ranch I | Busch Ranch Wind Farm is a 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm. |
Busch Ranch II | Busch Ranch II wind project is under construction as a 60 MW wind farm near Pueblo, Colorado, built by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement. |
Ceiling Test | Related to our Oil and Gas subsidiary, capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties. |
CAPP | Customer Appliance Protection Plan - acquired in the SourceGas Acquisition |
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 (doing business as Black Hills Energy) |
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. |
Choice Gas Program | The unbundling of the natural gas service from the distribution component, which opens up the gas supply for competition allowing customers to choose from different natural gas suppliers. Black Hills Gas Distribution distributes the gas and Black Hills Energy Services is one of the Choice Gas suppliers. |
City of Gillette | Gillette, Wyoming |
Colorado Electric | Black Hills Colorado Electric, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
Colorado Gas | Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
Colorado Interstate Gas (CIG) | Colorado Interstate Natural Gas Pricing Index |
Consolidated Indebtedness to Capitalization Ratio | Any Indebtedness outstanding at such time, divided by Capital at such time. Capital being Consolidated Net-Worth (excluding noncontrolling interest) plus Consolidated Indebtedness (including letters of credit and certain guarantees issued) as defined within the current Credit Agreement. |
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 |
CPP | Clean Power Plan |
CP Program | Commercial Paper Program |
CPUC | Colorado Public Utilities Commission |
CT | Combustion turbine |
CTII | The 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette. |
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 |
Dodd-Frank | Dodd-Frank Wall Street Reform and Consumer Protection Act |
DSM | Demand Side Management |
DRSPP | Dividend Reinvestment and Stock Purchase Plan |
Dth | Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu) |
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 |
EIA | Environmental Improvement Adjustment |
EPA | United States Environmental Protection Agency |
Equity Unit | Each Equity Unit has a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC RSNs due 2028. |
EWG | Exempt Wholesale Generator |
FASB | Financial Accounting Standards Board |
FDIC | Federal Deposit Insurance Corporation |
FERC | United States Federal Energy Regulatory Commission |
Fitch | Fitch Ratings |
GAAP | Accounting principles generally accepted in the United States of America |
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. |
Iowa Gas | Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
IPP | Independent power producer |
IPP Transaction | The July 11, 2008 sale of seven of our IPP plants |
IRS | United States Internal Revenue Service |
Kansas Gas | Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
kV | Kilovolt |
LIBOR | London Interbank Offered Rate |
LOE | Lease Operating Expense |
Loveland Area Project | Part of the Western Area Power Association transmission system |
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 |
Mcfd | Thousand cubic feet per day |
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 Plant |
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 |
NAV | Net Asset Value |
Nebraska Gas | Black Hills Nebraska Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings (doing business as Black Hills Energy) |
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 |
NPSC | Nebraska Public Service Commission |
NWPL | Northwest Interstate Natural Gas Pricing Index |
NYMEX | New York Mercantile Exchange |
NYSE | New York Stock Exchange |
OCI | Other Comprehensive Income |
OPEB | Other Post-Employment Benefits |
OSHA | Occupational Safety & Health Administration |
OSM | U.S. Department of the Interior’s Office of Surface Mining |
PCA | Power Cost Adjustment |
PCCA | Power Capacity Cost Adjustment |
Peak View | 60 MW wind generating project owned by Colorado Electric, placed in service on November 7, 2016 and adjacent to Busch Ranch I Wind Farm |
PPA | Power Purchase Agreement |
PSCo | Public Service Company of Colorado |
PUHCA 2005 | Public Utility Holding Company Act of 2005 |
REPA | Renewable Energy Purchase Agreement |
Revolving Credit Facility | Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2023 |
RMNG | Rocky Mountain Natural Gas, a regulated gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas Distribution in western Colorado (doing business as Black Hills Energy) |
RSNs | Remarketable junior subordinated notes, issued on November 23, 2015 |
SAIDI | System Average Interruption Duration Index |
SDPUC | South Dakota Public Utilities Commission |
SEC | U. S. Securities and Exchange Commission |
Service Guard | Home appliance repair product offering for both natural gas and electric |
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. |
SPP | Southwest Power Pool, Inc. which oversees the bulk electric grid and wholesale power market in the central United States |
SourceGas | SourceGas Holdings, LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy) |
SourceGas Acquisition | The acquisition of SourceGas Holdings LLC by Black Hills Utility Holdings |
SourceGas Transaction | On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. |
South Dakota Electric | Includes Black Hills Power operations in South Dakota, Wyoming and Montana |
SSIR | System Safety and Integrity Rider |
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. |
TCJA | Tax Cuts and Jobs Act enacted on December 22, 2017 |
TCIR | Total Case Incident Rate (average number of work-related injuries incurred by 100 workers during a one-year period) |
Tech Services | Non-regulated product lines within Black Hills Corporation that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owner gas infrastructure facilities, typically through one-time contracts. |
TFA | Transmission Facility Adjustment |
VEBA | Voluntary Employee Benefit Association |
VIE | Variable Interest Entity |
WDEQ | Wyoming Department of Environmental Quality |
WECC | Western Electricity Coordinating Council |
Winter Storm Atlas | An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history. |
WPSC | Wyoming Public Service Commission |
WRDC | Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings |
Wyodak Plant | Wyodak, a 362 MW mine-mouth coal-fired plant in Gillette, Wyoming, owned 80% by PacifiCorp and 20% by Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant. |
Wyoming Electric | Includes Cheyenne Light’s electric utility operations |
Wyoming Gas | Includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations |
ITEMS 1 AND 2. | BUSINESS AND PROPERTIES |
System Peak Demand (in MW) | |||||||||
2018 | 2017 | 2016 | |||||||
Summer | Winter | Summer | Winter | Summer | Winter | ||||
South Dakota Electric | 437 | 379 | 447 | 402 | 438 | 389 | |||
Wyoming Electric (a) | 254 | 238 | 249 | 230 | 236 | 230 | |||
Colorado Electric (b) | 413 | 313 | 398 | 299 | 412 | 302 | |||
Total Electric Utilities’ Peak Demands | 1,104 | 930 | 1,094 | 931 | 1,086 | 921 |
(a) | The July 2018 summer peak load of 254 surpassed previous summer peak record load of 249 set in July 2017. The December 2018 winter peak load of 238 surpassed the previous winter peak record load of 230 set in December 2016. |
(b) | The July 2018 summer peak load of 413 surpassed previous summer peak record load of 412 set in July 2016. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011. |
Unit | Fuel Type | Location | Ownership Interest % | Owned Capacity (MW) | Year Installed |
South Dakota Electric: | |||||
Cheyenne Prairie (a) | Gas | Cheyenne, Wyoming | 58% | 55.0 | 2014 |
Wygen III (b) | Coal | Gillette, Wyoming | 52% | 57.2 | 2010 |
Neil Simpson II | Coal | Gillette, Wyoming | 100% | 90.0 | 1995 |
Wyodak (c) | 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 |
Wyoming Electric: | |||||
Cheyenne Prairie (a) | Gas | Cheyenne, Wyoming | 42% | 40.0 | 2014 |
Cheyenne Prairie CT (a) | Gas | Cheyenne, Wyoming | 100% | 37.0 | 2014 |
Wygen II | Coal | Gillette, Wyoming | 100% | 95.0 | 2008 |
Colorado Electric (e): | |||||
Busch Ranch I Wind Farm (d) | Wind | Pueblo, Colorado | 50% | 14.5 | 2012 |
Peak View Wind Farm | Wind | Pueblo, Colorado | 100% | 60.0 | 2016 |
Pueblo Airport Generation | Gas | Pueblo, Colorado | 100% | 180.0 | 2011 |
Pueblo Airport Generation CT | Gas | Pueblo, Colorado | 100% | 40.0 | 2016 |
AIP Diesel | Oil | Pueblo, Colorado | 100% | 10.0 | 2001 |
Diesel #1 and #3-5 | Oil | Pueblo, Colorado | 100% | 8.0 | 1964 |
Diesel #1-5 | Oil | Rocky Ford, Colorado | 100% | 10.0 | 1964 |
Total MW Capacity | 939.1 |
(a) | Cheyenne Prairie, a 132 MW natural gas-fired power generation facility supports the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW). |
(b) | Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric 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. |
(c) | Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by South Dakota Electric. This baseload plant is operated by PacifiCorp and our WRDC coal mine supplies all of the fuel for the plant. |
(d) | Busch Ranch I Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and Black Hills Electric Generation owns the remaining 50%. Black Hills Electric Generation purchased the remaining 50% from AltaGas on December 11, 2018. Colorado Electric has a PPA with Black Hills Electric Generation for its 14.5 MW of power from the wind farm. The terms of the PPA are the same as the previous PPA with AltaGas. |
(e) | On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation for the 60 MW Busch Ranch II wind project. The project is currently under construction and is expected to be in service by the end of 2019. |
Fuel Source (dollars per MWh) | 2018 | 2017 | 2016 | ||||||
Coal | $ | 11.10 | $ | 10.95 | $ | 11.27 | |||
Natural Gas | $ | 33.42 | $ | 34.05 | $ | 30.59 | |||
Diesel Oil (a) | $ | 329.27 | $ | 210.11 | $ | 149.13 | |||
Total Average Fuel Cost | $ | 13.53 | $ | 12.80 | $ | 12.99 | |||
Purchased Power - Coal, Gas and Oil | $ | 45.62 | $ | 45.63 | $ | 48.36 | |||
Purchased Power - Renewable Sources | $ | 54.31 | $ | 53.08 | $ | 51.95 |
(a) | Included in the Price per MWh for Diesel Oil are unit start-up costs. The diesel-fueled generating units are generally used as supplemental peaking units and the cost per MWh is reflective of how often the units are started and how long the units are run. |
Power Supply | 2018 | 2017 | 2016 | |||
Coal | 32 | % | 32 | % | 33 | % |
Gas, Oil and Wind | 10 | 8 | 7 | |||
Total Generated | 42 | 40 | 40 | |||
Purchased (a) | 58 | 60 | 60 | |||
Total | 100 | % | 100 | % | 100 | % |
(a) | Wind represents approximately 6%, 6% and 7% of our purchased power in 2018, 2017, and 2016, respectively. |
• | South Dakota Electric’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 reported and accounted for as a capital lease within our business segments and is eliminated on the accompanying Consolidated Financial Statements; |
• | Colorado Electric’s PPA with Black Hills Electric Generation, which provides up to 14.5 MW of wind energy from Black Hills Electric Generation’s owned interest in the Busch Ranch I Wind Farm. This PPA is the same as the previous agreement with AltaGas, which expires on October 16, 2037; |
• | Wyoming Electric’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 Wyoming Electric to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019. On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019. |
• | Wyoming Electric’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 Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility’s output to South Dakota Electric; |
• | Wyoming Electric’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 Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of the facility’s output to South Dakota Electric; |
• | Wyoming Electric and South Dakota Electric’s Generation Dispatch Agreement requires South Dakota Electric to purchase all of Wyoming Electric’s excess energy; and |
• | South Dakota Electric’s PPA with Platte River Power Authority to purchase up to 12 MW of wind energy through Platte River Power Authority’s agreement with Silver Sage. This agreement will expire September 30, 2029. |
• | 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, South Dakota Electric will provide MDU with 25 MW from its other generation facilities or from system purchases with reimbursement of costs by MDU; |
• | South Dakota Electric has an agreement through December 31, 2023 to provide 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, South Dakota Electric 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, South Dakota Electric will also provide the City of Gillette its operating component of spinning reserves; |
• | South Dakota Electric has an agreement through December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals; and |
• | South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2028. The terms of the contract run from June 1 through May 31 for each interval listed below. 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: |
2019-2020 | 15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
2020-2022 | 15 MW - 7 MW contingent on Wygen III and 8 MW contingent on Neil Simpson II |
2022-2023 | 15 MW - 8 MW contingent on Wygen III and 7 MW contingent on Neil Simpson II |
2023-2028 | 10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
Utility | State | Transmission (in Line Miles) | Distribution (in Line Miles) | ||
South Dakota Electric | South Dakota, Wyoming | 1,231 | 2,539 | ||
South Dakota Electric - Jointly Owned (a) | South Dakota, Wyoming | 44 | — | ||
Wyoming Electric | Wyoming | 49 | 1,291 | ||
Colorado Electric | Colorado | 598 | 3,106 |
(a) | South Dakota Electric 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 SPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. South Dakota Electric’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 - |
◦ | South Dakota Electric, Wyoming Electric, 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. |
◦ | South Dakota Electric and Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie. |
• | Jointly Owned Facilities - |
◦ | South Dakota Electric, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby South Dakota Electric charges the City of Gillette and MDU for administrative services, plant operations and maintenance for its share of the Wygen III generating facility for the life of the plant. |
◦ | Colorado Electric and Black Hills Electric Generation are parties to a shared joint ownership agreement whereby Colorado Electric charges Black Hills Electric Generation for operations and maintenance for its share of the Busch Ranch I Wind Farm. |
Subsidiary | Jurisdic-tion | Authorized Rate of Return on Equity | Authorized Return on Rate Base | Authorized Capital Structure Debt/Equity | Authorized Rate Base (in millions) | Effective Date | Additional Tariffed Mechanisms | Percentage of Power Marketing Profit Shared with Customers |
South Dakota Electric | WY | 9.9% | 8.13% | 46.7%/53.3% | $46.8 | 10/2014 | ECA | 65% |
SD | Global Settlement | 7.76% | Global Settlement | $543.9 | 10/2014 | ECA, TCA, Energy Efficiency Cost Recovery/DSM | 70% | |
SD | 7.76% | 5/2014 | Transmission Facility Adjustment (TFA) Tariff | N/A | ||||
SD | 7.76% | 6/2011 | Environmental Improvement Adjustment (EIA) Tariff | N/A | ||||
FERC | 10.8% | 8.76% | 43%/57% | 2/2009 | FERC Transmission Tariff | N/A | ||
Wyoming 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 | |
Colorado Electric | CO | 9.37% | 7.43% | 47.6%/52.4% | $539.6 | 1/2017 | ECA, TCA, PCCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment | 90% |
CO | 9.37% | 6.02% | 67.3%/32.7% | $57.9 | 1/2017 | Clean Air Clean Jobs Act Adjustment Rider | N/A |
• | An approved annual Environmental Improvement Adjustment (EIA) tariff which recovers costs associated with generation plant environmental improvements. South Dakota Electric also has a Transmission Facility Adjustment (TFA) tariff which recovers the costs associated with transmission facility improvements. The EIA and TFA were suspended for a six-year moratorium period effective July 1, 2017. See Note 13 in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. |
• | An annual adjustment clause which provides for the over or under recovery of fuel and purchased power cost incurred to serve South Dakota customers. Additionally, this ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 100% of off-system power marketing operating income from the first $1.0 million of power marketing margin from short-term sales and a credit equal to 70% of power marketing margins from short-term sales in excess of the first $1.0 million. South Dakota Electric retains the remaining 30%. During the six-year moratorium period effective July 1, 2017, the 100% credit of power marketing margin increased from $1.0 million to $2.0 million. The ECA methodology allows us 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. |
• | An approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff. |
• | An annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. The annual cost adjustment allows for recovery of 85% of coal and coal-related cost per kWh variances from base, and recovery of 95% of purchased power, transmission, and natural gas cost per kWh variances from base. |
• | An approved FERC Transmission Tariff that determines the revenue component of Wyoming Electric’s open access transmission tariff. |
• | A quarterly ECA rider 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, and the sharing of off-system sales margins, less certain operating costs (customer receives 90%). 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. |
• | An annual TCA rider that includes nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism. |
• | A Clean Air Clean Jobs Act Adjustment rider rate that collects the authorized revenue requirement for the 40 MW combustion turbine placed in service on December 31, 2016 with rates effective January 1, 2017. |
• | A Renewable Energy Standard Adjustment rider that is specifically designed for meeting the requirements of Colorado’s renewable energy standard and most recently includes cost recovery for Peak View. |
Degree Days | 2018 | 2017 | 2016 | ||||||
Actual | Variance from 30-Year Average (b) | Actual | Variance from 30-Year Average (b) | Actual | Variance from 30-Year Average (b) | ||||
Heating Degree Days: | |||||||||
South Dakota Electric | 7,749 | 8% | 6,870 | (4)% | 6,402 | (10)% | |||
Wyoming Electric | 7,036 | (7)% | 6,623 | (12)% | 6,363 | (14)% | |||
Colorado Electric | 5,119 | 4% | 4,693 | (16)% | 4,658 | (16)% | |||
Combined (a) | 6,405 | 3% | 5,826 | (11)% | 5,595 | (13)% | |||
Cooling Degree Days: | |||||||||
South Dakota Electric | 488 | (23)% | 709 | 11% | 646 | (4)% | |||
Wyoming Electric | 430 | 24% | 429 | 23% | 460 | 31% | |||
Colorado Electric | 1,420 | 58% | 1,027 | 14% | 1,358 | 42% | |||
Combined (a) | 902 | 29% | 798 | 14% | 935 | 26% |
(a) | The combined degree days are calculated based on a weighted average of total customers by state. |
(b) | 30-Year Average is from NOAA Climate Normals. |
Electric Revenue (in thousands) | Quantities Sold (MWh) | ||||||||||||||||
2018 | 2017 | 2016 | 2018 | 2017 | 2016 | ||||||||||||
Residential | $ | 218,558 | $ | 210,172 | $ | 208,725 | 1,450,585 | 1,390,952 | 1,395,097 | ||||||||
Commercial | 250,894 | 258,754 | 258,768 | 2,034,917 | 2,038,495 | 2,067,486 | |||||||||||
Industrial | 124,668 | 122,958 | 118,181 | 1,682,074 | 1,598,755 | 1,515,553 | |||||||||||
Municipal | 17,871 | 18,144 | 17,821 | 160,913 | 160,882 | 162,383 | |||||||||||
Subtotal Retail Revenue - Electric | 611,991 | 610,028 | 603,495 | 5,328,489 | 5,189,084 | 5,140,519 | |||||||||||
Contract Wholesale | 33,688 | 30,435 | 17,037 | 900,854 | 722,659 | 246,630 | |||||||||||
Off-system/Power Marketing Wholesale | 24,800 | 21,111 | 22,355 | 673,994 | 661,263 | 769,843 | |||||||||||
Other (a) | 40,972 | 43,076 | 34,394 | — | — | — | |||||||||||
Total Revenue and Energy Sold | 711,451 | 704,650 | 677,281 | 6,903,337 | 6,573,006 | 6,156,992 | |||||||||||
Other Uses, Losses or Generation, net | — | — | — | 470,250 | 468,179 | 433,400 | |||||||||||
Total Revenue and Energy | 711,451 | 704,650 | 677,281 | 7,373,587 | 7,041,185 | 6,590,392 | |||||||||||
Less cost of fuel and purchased power | 277,093 | 268,405 | 261,349 | ||||||||||||||
Gross Margin (b) | $ | 434,358 | $ | 436,245 | $ | 415,932 |
(a) | Other revenue in 2018 reflects the impact of revenue reserved in accordance with the TCJA. |
(b) | Non-GAAP measure. |
Electric Revenue (in thousands) | Gross Margin (a) (in thousands) | Quantities Sold (MWh) (b) | |||||||||||||||||||||||||
2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||||||||||
South Dakota Electric | $ | 298,080 | $ | 288,433 | $ | 267,632 | $ | 205,194 | $ | 200,795 | $ | 192,606 | 3,360,396 | 3,187,392 | 2,767,315 | ||||||||||||
Wyoming Electric | 162,153 | 165,127 | 157,606 | 83,516 | 89,371 | 85,036 | 1,861,273 | 1,762,117 | 1,677,421 | ||||||||||||||||||
Colorado Electric | 251,218 | 251,090 | 252,043 | 145,648 | 146,079 | 138,290 | 2,151,918 | 2,091,676 | 2,145,656 | ||||||||||||||||||
Total Revenue, Gross Margin, and Quantities Sold | $ | 711,451 | $ | 704,650 | $ | 677,281 | $ | 434,358 | $ | 436,245 | $ | 415,932 | 7,373,587 | 7,041,185 | 6,590,392 |
(a) | Non-GAAP measure. |
(b) | Total MWh includes Other Uses, Losses or Generation, net, which is approximately 6%, 6%, and 7% for South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively. |
Quantities Generated and Purchased (MWh) | 2018 | 2017 | 2016 | |||
Coal-fired | 2,368,506 | 2,230,617 | 2,201,757 | |||
Natural Gas and Oil | 446,373 | 307,815 | 343,001 | |||
Wind | 253,180 | 239,472 | 80,582 | |||
Total Generated | 3,068,059 | 2,777,904 | 2,625,340 | |||
Purchased | 4,305,528 | 4,263,281 | 3,965,052 | |||
Total Generated and Purchased | 7,373,587 | 7,041,185 | 6,590,392 |
Quantities Generated and Purchased (MWh) | 2018 | 2017 | 2016 | |||
Generated: | ||||||
South Dakota Electric | 1,734,222 | 1,581,915 | 1,585,870 | |||
Wyoming Electric | 852,391 | 798,024 | 805,351 | |||
Colorado Electric | 481,446 | 397,965 | 234,119 | |||
Total Generated | 3,068,059 | 2,777,904 | 2,625,340 | |||
Purchased: | ||||||
South Dakota Electric | 1,626,174 | 1,605,477 | 1,181,445 | |||
Wyoming Electric | 1,008,882 | 964,093 | 872,070 | |||
Colorado Electric | 1,670,472 | 1,693,711 | 1,911,537 | |||
Total Purchased | 4,305,528 | 4,263,281 | 3,965,052 | |||
Total Generated and Purchased | 7,373,587 | 7,041,185 | 6,590,392 |
Customers at End of Year | 2018 | 2017 | 2016 | |||
Residential | 181,459 | 179,911 | 178,333 | |||
Commercial | 29,299 | 29,354 | 29,086 | |||
Industrial | 84 | 86 | 88 | |||
Other | 1,030 | 914 | 1,001 | |||
Total Electric Customers at End of Year | 211,872 | 210,265 | 208,508 |
Customers at End of Year | 2018 | 2017 | 2016 | |||
South Dakota Electric | 72,533 | 72,184 | 71,353 | |||
Wyoming Electric | 42,694 | 42,130 | 41,531 | |||
Colorado Electric | 96,645 | 95,951 | 95,624 | |||
Total Electric Customers at End of Year | 211,872 | 210,265 | 208,508 |
State | Working Capacity (Mcf) | Cushion Gas (Mcf) (a) | Total Capacity (Mcf) | Maximum Daily Withdrawal Capability (Mcfd) | |||||
Arkansas | 8,442,700 | 12,950,000 | 21,392,700 | 196,000 | |||||
Colorado | 2,360,895 | 6,165,315 | 8,526,210 | 30,000 | |||||
Wyoming | 5,733,900 | 17,145,600 | 22,879,500 | 32,950 | |||||
Total | 16,537,495 | 36,260,915 | 52,798,410 | 258,950 |
(a) | Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure. |
System Infrastructure (in line miles) as of | Intrastate Gas Transmission Pipelines | Gas Distribution Mains | Gas Distribution Service Lines | |||
December 31, 2018 | ||||||
Arkansas | 932 | 4,803 | 1,122 | |||
Colorado | 689 | 6,699 | 2,457 | |||
Nebraska | 1,263 | 8,539 | 3,203 | |||
Iowa | 164 | 2,791 | 2,667 | |||
Kansas | 325 | 2,868 | 1,347 | |||
Wyoming | 1,327 | 3,447 | 1,215 | |||
Total | 4,700 | 29,147 | 12,011 |
Degree Days | 2018 | 2017 | 2016 | ||||||||
Actual | Variance From 30-Year Average (c) | Actual | Variance From 30-Year Average (c) | Actual | Variance From 30-Year Average (c) | ||||||
Heating Degree Days: | |||||||||||
Arkansas (a) | 4,169 | 3% | 3,295 | (19)% | 2,397 | (41)% | |||||
Colorado | 6,136 | (7)% | 5,728 | (14)% | 5,762 | (13)% | |||||
Nebraska | 6,563 | 6% | 5,554 | (10)% | 5,457 | (12)% | |||||
Iowa | 7,192 | 6% | 6,149 | (9)% | 5,997 | (11)% | |||||
Kansas (a) | 5,242 | 7% | 4,452 | (9)% | 4,307 | (12)% | |||||
Wyoming | 7,425 | (1)% | 7,123 | (5)% | 6,750 | (10)% | |||||
Combined (b) | 6,628 | 2% | 5,862 | (10)% | 5,823 | (11)% |
(a) | Arkansas Gas has a weather normalization mechanism in effect during the months of November through April for customers with residential and certain business rate schedules. Kansas Gas has a weather normalization mechanism within its residential and business rate structure. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, while Kansas uses multiple locations. The weather normalization mechanisms in both Arkansas and Kansas minimize weather impact on gross margins (a non-GAAP measure). |
(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. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April. |
(c) | 30-Year Average is from NOAA climate normals. |
Subsidiary | Jurisdic-tion | Authorized Rate of Return on Equity | Authorized Return on Rate Base | Authorized Capital Structure Debt/Equity | Authorized Rate Base (in millions) | Effective Date | Additional Tariffed Mechanisms |
Gas Utilities: | |||||||
Arkansas Gas | AR | 9.61% | 6.82% (a) | 50.9%/49.1% | $451.5 (b) | 10/2018 | GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative/Regulatory Mandate and Relocations Rider, Energy Efficiency, Weather Normalization Adjustment, Billing Determinant Adjustment |
Colorado Gas | CO | 9.6% | 8.41% | 50%/50% | $57.5 | 12/2012 | GCA, Energy Efficiency Cost Recovery/DSM |
Colorado Gas Dist. | CO | 10.0% | 8.02% | 49.52%/ 50.48% | $127.1 | 12/2010 | GCA, DSM |
RMNG | CO | 9.9% | 6.71% | 53.37%/ 46.63% | $118.7 | 6/2018 | System Safety Integrity Rider, Liquids/Off-system/Market Center Services Revenue Sharing |
Iowa Gas | IA | Global Settlement | Global Settlement | Global Settlement | $109.2 | 2/2011 | GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism, Gas Supply Optimization revenue sharing |
Kansas Gas | KS | Global Settlement | Global Settlement | Global Settlement | $127.9 | 1/2015 | GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Pension Levelized Adjustment |
Nebraska Gas | NE | 10.1% | 9.11% | 48%/52% | $161.0 | 9/2010 | GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge |
Nebraska Gas Dist. | NE | 9.6% | 7.67% | 48.84%/ 51.16% | $87.6/ $69.8 (c) | 6/2012 | Choice Gas Program, System Safety and Integrity Rider, Bad Debt expense recovered through Choice Supplier Fee |
Wyoming Gas (Northwest Wyoming) | WY | 9.6% | 7.75% | 46%/54% | $12.9 | 9/2018 | GCA |
Wyoming Gas | WY | 9.9% | 7.98% | 46%/54% | $59.6 | 10/2014 | GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery on Acquisition Adjustment |
Wyoming Gas Dist. | WY | 9.92% | 7.98% | 49.66%/ 50.34% | $100.5 | 1/2011 | Choice Gas Program, Purchased GCA, Usage Per Customer Adjustment |
(a) | Arkansas Gas return on rate base adjusted to remove current liabilities from rate case capital structure for comparison with other subsidiaries. |
(b) | Arkansas Gas rate base is adjusted to include current liabilities for comparison with other subsidiaries. |
(c) | Total Nebraska Gas Distribution rate base of $87.6 million includes amounts allocated to serve non-jurisdictional and agricultural customers. Jurisdictional Nebraska rate base of $69.8 million excludes those amounts allocated to serve non-jurisdictional and agricultural customers and is used for calculation of jurisdictional base rates. |
Gas Utility Jurisdiction | Cost Recovery Mechanisms | |||||||
DSM/Energy Efficiency | Integrity Additions | Bad Debt | Weather Normal | Pension Recovery | Gas Cost | Billing Determinant Adjustment | Revenue Decoupling | |
Arkansas Gas | þ | þ | þ | þ | þ | |||
Colorado Gas | þ | þ | ||||||
Colorado Gas Dist. | þ | þ | ||||||
RMNG | N/A | þ | N/A | N/A | N/A | N/A | N/A | N/A |
Iowa Gas | þ | þ | þ | |||||
Kansas Gas | þ | þ | þ | þ | þ | |||
Nebraska Gas | þ | þ | þ | |||||
Nebraska Gas Dist. | þ | þ | ||||||
Wyoming Gas (a) | þ | þ | ||||||
Wyoming Gas Dist. | þ | þ |
Revenue (in thousands) | Gross Margin (a) (in thousands) | Quantities Sold and Transported (Dth) | |||||||||||||||||||||||||
2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||||||||||
Residential | $ | 567,785 | $ | 499,852 | $ | 433,106 | $ | 276,858 | $ | 255,626 | $ | 228,512 | 65,352,164 | 54,645,598 | 49,390,451 | ||||||||||||
Commercial | 214,718 | 197,054 | 162,547 | 82,529 | 78,249 | 67,375 | 30,753,361 | 27,315,871 | 24,037,861 | ||||||||||||||||||
Industrial | 26,466 | 24,454 | 21,245 | 7,056 | 6,226 | 5,601 | 6,309,211 | 5,855,053 | 5,737,430 | ||||||||||||||||||
Other (b) | (7,899 | ) | 8,647 | 12,694 | (7,899 | ) | 8,647 | 12,694 | — | — | — | ||||||||||||||||
Total Distribution | 801,070 | 730,007 | 629,592 | 358,544 | 348,748 | 314,182 | 102,414,736 | 87,816,522 | 79,165,742 | ||||||||||||||||||
Transportation and Transmission | 141,854 | 135,824 | 139,490 | 141,850 | 135,824 | 139,282 | 148,299,003 | 141,600,080 | 126,927,565 | ||||||||||||||||||
Total Regulated | 942,924 | 865,831 | 769,082 | 500,394 | 484,572 | 453,464 | 250,713,739 | 229,416,602 | 206,093,307 | ||||||||||||||||||
Non-regulated Services | 82,383 | 81,799 | 69,261 | 62,760 | 53,455 | 32,714 | — | — | — | ||||||||||||||||||
Total Revenue, Gross Margin and Quantities Sold | $ | 1,025,307 | $ | 947,630 | $ | 838,343 | $ | 563,154 | $ | 538,027 | $ | 486,178 | 250,713,739 | 229,416,602 | 206,093,307 |
(a) | Non-GAAP measure. |
(b) | Other revenue and Gross Margin in 2018 reflects the impact of revenue reserved in accordance with the TCJA. |
Revenue (in thousands) | Gross Margin (a) (in thousands) | Quantities Sold & Transported (Dth) | |||||||||||||||||||||||||
2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||||||||||
Arkansas | $ | 176,660 | $ | 153,691 | $ | 106,958 | $ | 100,917 | $ | 94,007 | $ | 69,840 | 30,931,390 | 26,491,537 | 19,177,438 | ||||||||||||
Colorado | 188,002 | 180,852 | 153,003 | 99,851 | 100,718 | 86,016 | 29,857,063 | 28,436,744 | 23,656,891 | ||||||||||||||||||
Nebraska | 278,969 | 252,631 | 244,992 | 164,513 | 154,259 | 146,831 | 81,658,938 | 73,890,509 | 67,796,021 | ||||||||||||||||||
Iowa | 161,843 | 143,446 | 130,776 | 68,384 | 66,619 | 64,170 | 40,668,682 | 37,013,645 | 35,383,990 | ||||||||||||||||||
Kansas | 112,306 | 105,576 | 100,670 | 55,226 | 53,841 | 54,247 | 31,387,672 | 28,251,947 | 26,463,314 | ||||||||||||||||||
Wyoming | 107,527 | 111,434 | 101,944 | 74,263 | 68,583 | 65,074 | 36,209,994 | 35,332,220 | 33,615,653 | ||||||||||||||||||
Total Revenue, Gross Margin and Quantities Sold | $ | 1,025,307 | $ | 947,630 | $ | 838,343 | $ | 563,154 | $ | 538,027 | $ | 486,178 | 250,713,739 | 229,416,602 | 206,093,307 |
(a) | Non-GAAP measure. |
Customers at End of Year | 2018 | 2017 | 2016 | |||
Residential | 821,624 | 806,744 | 800,980 | |||
Commercial (a) | 82,498 | 86,461 | 84,049 | |||
Industrial | 2,221 | 2,214 | 2,050 | |||
Transportation/Other | 147,550 | 146,839 | 143,673 | |||
Total Customers at End of Year | 1,053,893 | 1,042,258 | 1,030,752 |
(a) | The decrease is 2018 is due to customer class reclassification to residential at our Colorado Gas utilities. |
Customers at End of Year | 2018 | 2017 | 2016 | |||
Arkansas | 171,978 | 169,303 | 166,512 | |||
Colorado | 186,759 | 181,876 | 177,394 | |||
Nebraska | 291,723 | 290,264 | 289,653 | |||
Iowa | 158,485 | 157,444 | 156,014 | |||
Kansas | 114,840 | 114,082 | 112,957 | |||
Wyoming | 130,108 | 129,289 | 128,222 | |||
Total Customers at End of Year | 1,053,893 | 1,042,258 | 1,030,752 |
• | Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% maximum annual 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. |
• | 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, South Dakota Electric 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 South Dakota Electric from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers South Dakota Electric has 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. |
Power Plants | Fuel Type | Location | Ownership Interest | Owned Capacity (MW) | In Service Date | |
Wygen I | Coal | Gillette, Wyoming | 76.5% | 68.9 | 2003 | |
Pueblo Airport Generation (a) | Gas | Pueblo, Colorado | 50.1% | 200.0 | 2012 | |
Busch Ranch I | Wind | Pueblo, Colorado | 50.0% | 14.5 | 2012 | |
283.4 |
(a) | Black Hills Colorado IPP owns and operates this facility. This facility provides capacity and energy to Colorado Electric under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital lease on the accompanying Consolidated Financial Statements. |
Quantities Sold, Generated and Purchased (MWh) (a) | 2018 | 2017 | 2016 | |||
Sold | ||||||
Black Hills Colorado IPP (b) | 1,000,577 | 943,618 | 1,223,949 | |||
Black Hills Wyoming (c) | 582,938 | 645,810 | 644,564 | |||
Black Hills Electric Generation | 5,873 | — | — | |||
Total Sold | 1,589,388 | 1,589,428 | 1,868,513 | |||
Generated | ||||||
Black Hills Colorado IPP (b) | 1,000,577 | 943,618 | 1,223,949 | |||
Black Hills Wyoming (c) | 501,945 | 577,124 | 543,546 | |||
Black Hills Electric Generation | 5,873 | — | — | |||
Total Generated | 1,508,395 | 1,520,742 | 1,767,495 | |||
Purchased | ||||||
Black Hills Wyoming | 83,213 | 69,377 | 85,993 | |||
Total Purchased | 83,213 | 69,377 | 85,993 |
(a) | Company use and losses are not included in the quantities sold, generated and purchased. |
(b) | The decrease in 2017 was driven by the joint dispatch agreement Colorado Electric joined in 2017. See details of this agreement above in the Electric Utilities segment. |
(c) | The decrease in 2018 was driven by a planned outage at Wygen I. |
• | Economy Energy PPA and other ancillary agreements |
◦ | Black Hills Wyoming has ancillary agreements with the City of Gillette, Wyoming to operate CTII, and provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreements include a 20-year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit. |
• | Operating and Maintenance Services Agreement |
◦ | In conjunction with the sale of the noncontrolling interest on April 14, 2016, an operating and maintenance services agreement was entered into between Black Hills Electric Generation and Black Hills Colorado IPP. This agreement sets forth the obligations and responsibilities of Black Hills Electric Generation as the operator of the generating facility owned by Black Hills Colorado IPP. This agreement is in effect from the date of the noncontrolling interest purchase and remains effective as long as the operator or one of its affiliates is responsible for managing the generating facilities in accordance with the noncontrolling interest agreement, or until termination by owner or operator. |
• | Shared Services Agreements |
◦ | South Dakota Electric, Wyoming Electric 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 parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric’s assets. |
◦ | Black Hills Colorado IPP, Wyoming Electric and South Dakota Electric are parties to a Spare Turbine Use Agreement, whereby Black Hills Colorado IPP charges South Dakota Electric and Wyoming Electric a monthly fee for the availability of a spare turbine to support the operation of Cheyenne Prairie Generating Station. |
◦ | Black Hills Colorado IPP and Black Hills Wyoming receive certain staffing and management services from BHSC. |
• | Jointly Owned Facilities |
◦ | Black Hills Wyoming and MEAN are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance on its share of the Wygen I generating facility over the life of the plant. |
◦ | Black Hills Electric Generation and Colorado Electric both own 50% of the Busch Ranch I Wind Farm. Black Hills Electric Generation purchased its 50% share in Busch Ranch I from AltaGas on December 11, 2018. See details of the PPA and ownership agreement discussed previously in the Electric Utilities segment. |
• | South Dakota Electric for use at the 90 MW Neil Simpson II plant to which we sell approximately 500,000 tons of coal each year. This contract is for the life of the plant; |
• | Wyoming Electric for use at the 95 MW Wygen II plant to which we sell approximately 550,000 tons of coal each year. This contract is for the life of the plant; |
• | The 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 0.375 million tons of coal per year for its 20% share of the power plant, subject to adjustments for planned outages. This contract expires December 31, 2022; |
• | The 110 MW Wygen III power plant owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons of coal each year. This contract expires June 1, 2060; |
• | The 90 MW Wygen I power plant owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons of coal each year. This contract expires June 30, 2038; and |
• | Certain regional industrial customers served by truck to which we sell a total of approximately 150,000 tons of coal each year. These contracts have terms of one to five years. |
Environmental Expenditure Estimates | Total (in thousands) | ||
2019 | $ | 1,503 | |
2020 | 1,088 | ||
2021 | 710 | ||
Total | $ | 3,301 |
• | In Rapid City, South Dakota, we have a 220,000 square foot corporate headquarters building, Horizon Point, which was completed in the fourth quarter of 2017. |
• | In Arkansas, Nebraska, Iowa, Colorado, Kansas and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 805,000 square feet utilized by our Gas Utilities. |
• | In South Dakota, Wyoming, Colorado and Montana we own various office, service center, storage, shop and warehouse space totaling approximately 240,000 square feet utilized by our Electric Utilities and Mining segments. |
Number of Employees | ||
Corporate | 499 | |
Electric Utilities and Gas Utilities | 2,301 | |
Mining and Power Generation | 63 | |
Total | 2,863 |
Utility | Number of Employees | Union Affiliation | Expiration Date of Collective Bargaining Agreement | |
South Dakota Electric | 128 | IBEW Local 1250 | March 31, 2022 | |
Wyoming Electric | 42 | IBEW Local 111 | June 30, 2019 | |
Colorado Electric | 103 | IBEW Local 667 | April 15, 2023 | |
Iowa Gas | 106 | IBEW Local 204 | July 31, 2020 | |
Kansas Gas | 19 | Communications Workers of America, AFL-CIO Local 6407 | December 31, 2019 | |
Nebraska Gas | 99 | IBEW Local 244 | March 13, 2022 | |
Nebraska Gas (a) | 146 | CWA Local 7476 | October 30, 2019 | |
Wyoming Gas (a) | 85 | CWA Local 7476 | October 30, 2019 | |
Total | 728 |
(a) | In the 2016 negotiations with the CWA Local 7476, the union agreed to disclaim their interest in Colorado Gas employees and to split the remaining bargaining unit into two distinct bargaining units, Nebraska Gas and Wyoming Gas. |
ITEM 1A. | RISK FACTORS |
• | Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically, or with cyber means, our ability to sell or deliver product and satisfy our contractual obligations may be hindered; |
• | Interruptions to supply of fuel and other commodities used in generation and distribution. Our utilities purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limit our utilities’ ability to operate their facilities; |
• | Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages; |
• | Operating hazards such as leaks, mechanical problems and accidents, including explosions affecting our natural gas distribution system, which could impact public safety, reliability and customer confidence; |
• | Operational limitations imposed by environmental and other regulatory requirements; |
• | Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak Plant; |
• | Labor relations. Approximately 25% of our employees are represented by a total of eight collective bargaining agreements; |
• | Our ability to transition and replace our retirement-eligible utility employees. At December 31, 2018, approximately 18% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement; |
• | Inability to recruit and retain skilled technical labor; and |
• | Disruption in the functioning of our information technology and network infrastructure which are vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions. |
• | The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals; |
• | Contractual restrictions upon the timing of scheduled outages; |
• | The cost of supplying or securing replacement power during scheduled and unscheduled outages; |
• | The unavailability or increased cost of equipment; |
• | The cost of recruiting and retaining or the unavailability of skilled labor; |
• | Supply interruptions, work stoppages and labor disputes; |
• | Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations; |
• | Opposition by members of public or special-interest groups; |
• | Weather interferences; |
• | Availability and cost of fuel supplies; |
• | Unexpected engineering, environmental and geological problems; and |
• | Unanticipated cost overruns. |
• | Our inability to obtain required governmental permits; |
• | Our inability to complete capital projects in a timely manner; |
• | Our inability to secure just and reasonable utility rates through regulatory proceedings; |
• | Our inability to obtain financing on acceptable terms, or at all; |
• | The possibility that one or more credit rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business; |
• | Our inability to attract and retain management or other key personnel; |
• | Our inability to negotiate acceptable construction, fuel supply, power sales or other material agreements; |
• | Reduced growth in the demand for utility services in the markets we serve; |
• | Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves or our power generation capacity; |
• | Fuel prices or fuel supply constraints; |
• | Pipeline capacity and transmission constraints; |
• | Competition within our industry and with producers of competing energy sources; and |
• | Changes in tax rates and policies. |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
ITEM 3. | LEGAL PROCEEDINGS |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
There were no equity securities acquired for the twelve months ended December 31, 2018. |
ITEM 6. | SELECTED FINANCIAL DATA |
Years Ended December 31, | 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||
(dollars in thousands, except per share amounts) | |||||||||||||||||||
Total Assets | $ | 6,963,327 | $ | 6,658,902 | $ | 6,541,773 | $ | 4,626,643 | $ | 4,216,752 | |||||||||
Property, Plant and Equipment | |||||||||||||||||||
Total property, plant and equipment | $ | 6,000,015 | $ | 5,567,518 | $ | 5,315,296 | $ | 3,849,309 | $ | 3,606,931 | |||||||||
Accumulated depreciation and depletion | (1,145,136 | ) | (1,026,088 | ) | (929,119 | ) | (794,695 | ) | (714,762 | ) | |||||||||
Total property, plant and equipment, net | $ | 4,854,879 | $ | 4,541,430 | $ | 4,386,177 | $ | 3,054,614 | $ | 2,892,169 | |||||||||
Capital Expenditures | |||||||||||||||||||
Continuing Operations | $ | 502,424 | $ | 337,689 | $ | 460,450 | $ | 289,896 | $ | 281,828 | |||||||||
Discontinued Operations | 2,402 | 23,222 | 6,669 | 168,925 | 109,439 | ||||||||||||||
Total Capital Expenditures | $ | 504,826 | $ | 360,911 | $ | 467,119 | $ | 458,821 | $ | 391,267 | |||||||||
Capitalization (excluding noncontrolling interests) | |||||||||||||||||||
Current maturities of long-term debt | $ | 5,743 | $ | 5,743 | $ | 5,743 | $ | — | $ | 275,000 | |||||||||
Notes payable | 185,620 | 211,300 | 96,600 | 76,800 | 75,000 | ||||||||||||||
Long-term debt, net of current maturities and deferred financing costs | 2,950,835 | 3,109,400 | 3,211,189 | (a) | 1,853,682 | 1,255,953 | |||||||||||||
Common stock equity (b) | 2,181,588 | 1,708,974 | 1,614,639 | 1,465,867 | 1,353,884 | ||||||||||||||
Total capitalization | $ | 5,323,786 | $ | 5,035,417 | $ | 4,928,171 | $ | 3,396,349 | $ | 2,959,837 | |||||||||
Capitalization Ratios | |||||||||||||||||||
Short-term debt, including current maturities | 4 | % | 4 | % | 2 | % | 2 | % | 12 | % | |||||||||
Long-term debt, net of current maturities | 55 | % | 62 | % | 65 | % | (a) | 55 | % | 42 | % | ||||||||
Common stock equity | 41 | % | 34 | % | 33 | % | 43 | % | 46 | % | |||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | |||||||||
Total Operating Revenues | $ | 1,754,268 | $ | 1,680,266 | $ | 1,538,916 | $ | 1,261,322 | $ | 1,338,456 | |||||||||
Net Income Available for Common Stock (h) | |||||||||||||||||||
Electric Utilities | $ | 78,940 | $ | 110,082 | $ | 85,827 | $ | 77,579 | $ | 57,270 | |||||||||
Gas Utilities | 160,283 | (g) | 65,795 | 59,624 | 39,306 | 44,151 | |||||||||||||
Power Generation | 20,777 | (c) | 46,479 | (c) | 25,930 | (c) | 32,650 | 28,516 | |||||||||||
Mining | 12,899 | 14,386 | 10,053 | 11,870 | 10,452 | ||||||||||||||
Corporate and intersegment eliminations | (7,570 | ) | (42,609 | ) | (d) | (44,302 | ) | (d) | (19,857 | ) | (d) | (7,927 | ) | ||||||
Income (loss) from continuing operations available for common stock | 265,329 | 194,133 | 137,132 | 141,548 | 132,462 | ||||||||||||||
Income (loss) from discontinued operations, net of tax (b) | (6,887 | ) | (17,099 | ) | (64,162 | ) | (173,659 | ) | (1,573 | ) | |||||||||
Net income (loss) available for common stock | $ | 258,442 | $ | 177,034 | $ | 72,970 | $ | (32,111 | ) | $ | 130,889 |
Years Ended December 31, | 2018 | 2017 | 2016 | 2015 | 2014 | |||||||||||||||
(dollars in thousands, except per share amounts) | ||||||||||||||||||||
Dividends Paid on Common Stock | $ | 106,591 | $ | 96,744 | $ | 87,570 | $ | 72,604 | $ | 69,636 | ||||||||||
Common Stock Data(e) (in thousands) | ||||||||||||||||||||
Shares outstanding, average basic | 54,420 | 53,221 | 51,922 | 45,288 | 44,394 | |||||||||||||||
Shares outstanding, average diluted | 55,486 | 55,120 | 53,271 | 45,288 | 44,598 | |||||||||||||||
Shares outstanding, end of year | 60,004 | 53,541 | 53,382 | 51,192 | 44,672 | |||||||||||||||
Earnings (Loss) Per Share of Common Stock (in dollars) | ||||||||||||||||||||
Basic earnings (loss) per average share - | ||||||||||||||||||||
Continuing operations | $ | 5.14 | $ | 3.92 | $ | 2.83 | $ | 3.12 | $ | 2.98 | ||||||||||
Discontinued operations (b) | (0.13 | ) | (0.32 | ) | (1.23 | ) | (3.83 | ) | (0.04 | ) | ||||||||||
Non-controlling interest | (0.26 | ) | (0.27 | ) | (0.19 | ) | — | — | ||||||||||||
Total | $ | 4.75 | $ | 3.33 | $ | 1.41 | $ | (0.71 | ) | $ | 2.94 | |||||||||
Diluted earnings (loss) per average share - | ||||||||||||||||||||
Continuing operations | $ | 5.04 | $ | 3.78 | $ | 2.75 | $ | 3.12 | $ | 2.97 | ||||||||||
Discontinued operations (b) | (0.12 | ) | (0.31 | ) | (1.20 | ) | (3.83 | ) | (0.04 | ) | ||||||||||
Non-controlling interest | (0.26 | ) | (0.26 | ) | (0.18 | ) | — | — | ||||||||||||
Total | $ | 4.66 | $ | 3.21 | $ | 1.37 | $ | (0.71 | ) | $ | 2.93 | |||||||||
Dividends Declared per Share | $ | 1.93 | $ | 1.81 | $ | 1.68 | $ | 1.62 | $ | 1.56 | ||||||||||
Book Value Per Share, End of Year | $ | 36.36 | $ | 31.92 | $ | 30.25 | $ | 28.63 | $ | 30.31 | ||||||||||
Return on Average Equity (f) | 13.6 | % | 11.7 | % | 8.9 | % | 10.0 | % | 10.0 | % |
(a) | The increase in 2016 includes the debt associated with the SourceGas acquisition (see Note 6 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K). |
(b) | On November 1, 2017, we made the decision to divest our Oil and Gas assets. 2017 includes an after-tax fair value impairment on held-for-sale assets of $13 million. 2016 includes non-cash after-tax impairment charges to crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax ceiling test impairment charges to crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million (see Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K). |
(c) | On April 14, 2016, Black Hills Electric Generation sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2018, 2017 and 2016 was reduced by $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest. |
(d) | 2017, 2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively. 2016 and 2015 also include after-tax internal labor costs attributable to the SourceGas Acquisition of $9.1 million and $3.0 million that otherwise would have been charged to other segments. |
(e) | On November 1, 2018, we issued 6.3 million shares of common stock upon conversion of our Equity Units. In 2016, we issued 1.97 million shares at an average share price of $60.95 under our ATM equity offering program. In November 2015, we issued 6.3 million shares of common stock, par value $1.00 per share at a price of $40.25. |
(f) | Calculated based on Net income (loss) from continuing operations available for common stock. |
(g) | The increase in 2018 included a $73 million tax benefit resulting from legal entity restructuring. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information. |
(h) | Net income (loss) from continuing operations for the year ended December 31, 2018 included approximately $4.0 million of income tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. The (expense) benefit impact to our operating segments and Corporate and Other for the year ended December. 31, 2018 was: Electric Utilities ($4.2) million; Gas Utilities $0.5 million; Power Generation ($0.7) million; Mining ($0.5) million; and Corporate and Other $0.9 million, respectively. Net Income from continuing operations for the year ended December 31, 2017 includes a net tax benefit of $7.6 million from the revaluation of deferred tax balances due to a decrease in the statutory Federal income tax rate resulting from the TCJA. The (expense) benefit impact to our operating segments and Corporate and Other for the year ended December 31, 2017 was: Electric Utilities $23 million; Gas Utilities ($6.8) million; Power Generation $24 million; Mining $2.7 million; and Corporate and Other ($35) million, respectively. |
ITEMS 7 & | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS |
and 7A. | OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET |
Actual | Planned | Planned | Planned | Planned | Planned | |||||||||||||
Capital Expenditures By Segment | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | ||||||||||||
(in millions) | ||||||||||||||||||
Electric Utilities | $ | 153 | $ | 200 | $ | 213 | $ | 191 | $ | 160 | $ | 137 | ||||||
Gas Utilities | 288 | 374 | 273 | 264 | 257 | 259 | ||||||||||||
Power Generation (a) | 38 | 72 | 9 | 8 | 10 | 4 | ||||||||||||
Mining | 19 | 8 | 7 | 11 | 10 | 7 | ||||||||||||
Corporate and Other | 12 | 16 | 22 | 8 | 6 | 7 | ||||||||||||
Total | $ | 510 | $ | 670 | $ | 524 | $ | 482 | $ | 443 | $ | 414 |
• | When generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run; especially when compared to power otherwise purchased from the open market through wholesale contracts that are periodically re-priced to reflect current and varying market conditions; |
• | Regulators participate in a planning process where long-term investments are designed to match long-term energy demand; |
• | The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of capital; and |
• | Investors are provided a long-term, reasonable, stable return on their investment. |
For the Years Ended December 31, | |||||||||||||||
2018 | Variance | 2017 | Variance | 2016 | |||||||||||
(in thousands) | |||||||||||||||
Revenue | |||||||||||||||
Revenue | $ | 1,893,743 | $ | 83,296 | $ | 1,810,447 | $ | 143,412 | $ | 1,667,035 | |||||
Intercompany eliminations | (139,475 | ) | (9,294 | ) | (130,181 | ) | (2,062 | ) | (128,119 | ) | |||||
$ | 1,754,268 | $ | 74,002 | $ | 1,680,266 | $ | 141,350 | $ | 1,538,916 | ||||||
Income from continuing operations available for common stock (a) | |||||||||||||||
Electric Utilities (a) | $ | 78,940 | $ | (31,142 | ) | $ | 110,082 | $ | 24,255 | $ | 85,827 | ||||
Gas Utilities (a) (b) (c) | 160,283 | 94,488 | 65,795 | 6,171 | 59,624 | ||||||||||
Power Generation (a) (d) | 20,777 | (25,702 | ) | 46,479 | 20,549 | 25,930 | |||||||||
Mining (a) | 12,899 | (1,487 | ) | 14,386 | 4,333 | 10,053 | |||||||||
272,899 | 36,157 | 236,742 | 55,308 | 181,434 | |||||||||||
Corporate and Other (a) (e) (f) | (7,570 | ) | 35,039 | (42,609 | ) | 1,693 | (44,302 | ) | |||||||
Income from continuing operations | 265,329 | 71,196 | 194,133 | 57,001 | 137,132 | ||||||||||
(Loss) from discontinued operations, net of tax (g) | (6,887 | ) | 10,212 | (17,099 | ) | 47,063 | (64,162 | ) | |||||||
Net income (loss) available for common stock | $ | 258,442 | $ | 81,408 | $ | 177,034 | $ | 104,064 | $ | 72,970 |
(a) | Income (loss) from continuing operations for 2018 included approximately $4.0 million of income tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. Income from continuing operations for 2017 includes a net tax benefit of $7.6 million from the revaluation of deferred tax balances due to a decrease in the statutory Federal income tax rate resulting from the TCJA. See the table below for the impact to each segment for both years. |
(b) | Income (loss) from continuing operations for 2018 included a $73 million tax benefit resulting from legal entity restructuring. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information. |
(c) | Income from continuing operations for 2017 includes a $4.1 million tax benefit from a true-up to the filed 2016 SourceGas tax returns relating to the SourceGas Acquisition. |
(d) | On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income (loss) from continuing operations available for common stock for 2018, 2017 and 2016 was reduced by $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest. |
(e) | Income from continuing operations for 2017 and 2016 include incremental SourceGas Acquisition costs, after-tax of $2.8 million and $30 million, respectively and after-tax internal labor costs attributable to the SourceGas Acquisition of $0.5 million and $9.1 million, respectively, that otherwise would have been charged to other business segments. |
(f) | Income from continuing operations for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016. |
(g) | Loss from discontinued operations in 2017 and 2016 included non-cash after-tax impairments of crude oil and natural gas properties of $13 million and $67 million, respectively. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
• | Gas Utilities’ earnings, excluding tax reform impacts, increased approximately $87 million primarily due to the recognition of a $73 million tax benefit resulting from legal entity restructuring (See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information); earnings also benefited from colder winter weather and increased sales of natural gas, offset by an increase in operating expenses; |
• | Earnings at our Mining segment, excluding tax reform impacts, increased $1.7 million primarily due to increased price per ton sold and lower operating expenses; |
• | Electric Utilities’ earnings, excluding tax reform impacts, decreased by $3.5 million due primarily to a settlement agreement with the WPSC which decreased gross margins by $2.6 million; other variances to the prior year were due to higher operating expenses driven by facility costs, employee costs, contractor and consulting expenses, and vegetation management expenses, partially offset by higher rider revenues from recent transmission investments, higher power marketing and wholesale margins, and favorable weather; |
• | Earnings at our Power Generation segment, excluding tax reform impacts, decreased $1.2 million primarily due to higher operating expenses; |
• | Corporate and Other expenses, excluding tax reform impacts, increased by approximately $1.3 million primarily due to higher intercompany allocations of tax expense, partially offset by a decrease in acquisition and transition costs occurring in the prior year; and |
• | In 2018, we recorded $4.0 million of income tax (expense) associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes compared to a net tax benefit of approximately $7.6 million as a result of the revaluation of deferred tax balances due to the decrease in the statutory Federal income tax rate as a result of the TCJA. The impacts to our operating segments and Corporate and Other for 2018 and 2017 were (in millions): |
Segment | 2018 | 2017 | ||||
Electric Utilities | $ | (4.2 | ) | $ | 23.4 | |
Gas Utilities | 0.5 | (6.8 | ) | |||
Power Generation | (0.7 | ) | 23.8 | |||
Mining | (0.5 | ) | 2.7 | |||
Corporate and Other | 0.9 | (35.5 | ) | |||
Total tax (expense) benefit | $ | (4.0 | ) | $ | 7.6 |
• | On December 17, 2018, South Dakota Electric and Wyoming Electric filed for approval with the SDPUC and WPSC, new voluntary renewable energy tariffs to serve customer requests for renewable energy resources. In addition, South Dakota Electric and Wyoming Electric filed a joint application with the WPSC for a CPCN to construct a $57 million, 40 MW wind generation project near Cheyenne, Wyoming. |
• | On December 6, 2018, Wyoming Electric set a new all-time winter peak load of 238 MW, exceeding the previous winter peak of 230 MW set on December 7, 2016. |
• | On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019. |
• | On October 31, 2018, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric will provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve several years of disputed issues related to PCA dockets before the commission. The settlement also stipulates that the adjustment for the variable cost segment of the Wygen I Power Purchase Agreement with Wyoming Electric (an affiliate company) will escalate by 3% annually through 2022. |
• | On October 3, 2018, Colorado Electric set a new all-time winter peak load of 313 MW, exceeding the previous winter peak of 310 MW set in February 2011. |
• | Cooling degree days for the year ended December 31, 2018 were 29% higher than the 30-year average (normal) compared to 14% higher than normal in 2017. |
• | Wyoming Electric and Colorado Electric set new summer peak loads: |
• | On July 10, 2018, Wyoming Electric set a new all-time peak load of 254 MW, exceeding the previous summer peak of 249 MW set in July 2017. |
• | On June 27, 2018, Colorado Electric set a new all-time peak load of 413 MW, exceeding the previous summer peak of 412 MW set in July 2016. |
• | On November 20, 2018, South Dakota Electric placed in service a 33-mile segment of a $70 million, 175-mile, 230-kV transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018. The remaining 94-mile segment is expected to be in service by the end of 2019. |
• | On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation for the 60 MW Busch Ranch II wind project. The project is currently under construction and is expected to be in service by the end of 2019. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard. |
• | Rate Review updates: |
• | On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments, in safety, reliability and system integrity. See Note 13 for additional details. |
• | On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018. |
• | On July 16, 2018, the WPSC approved our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018. |
• | In Colorado, RMNG implemented new rates after approval of a settlement of a rate review filed in October 2017. The settlement included $1.1 million in annual revenue increases and an extension of SSIR to recover costs from 2018 through 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA. |
• | On November 20, 2018, Wyoming Gas received approval from the WPSC for a CPCN to construct a new $54 million, 35-mile natural gas pipeline to enhance supply reliability and delivery capacity for approximately 57,000 customers in central Wyoming. The pipeline, known as the Natural Bridge Pipeline, is planned to be in service in late 2019. |
• | Certain legal entity restructuring transactions occurred on March 31, 2018 and December 31, 2018 as part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years. As a result of these transactions, additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, were recorded with a corresponding deferred tax benefit recorded on the Consolidated Statements of Income. |
• | Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than the 30-year average (normal) compared to 10% lower than normal in 2017. |
• | On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in the 29 MW Busch Ranch I Wind Farm, previously owned by AltaGas, for $16 million. |
• | On April 25, 2018, Black Hills Electric Generation was selected to provide 60 MW of renewable energy to Colorado Electric from the Busch Ranch II wind project, which is expected to be in service by the end of 2019. |
• | On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds were used to pay off $250 million of debt maturing in January 2019 and other short-term debt. |
• | On October 11, 2018, Fitch affirmed Black Hills’ credit rating at BBB+ and maintained a Stable outlook. |
• | On August 17, 2018, we completed a public debt offering of $400 million principal amount of 4.350% senior unsecured notes. The proceeds were used to repay the $299 million principal amount of our RSNs due 2028 and pay down short-term debt. |
• | On August 9, 2018, S&P upgraded Black Hills’ credit rating to BBB+ with a Stable outlook and South Dakota Electric’s credit rating to A. |
• | On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of$750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former Revolving Credit Facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and the banks increasing or providing new commitments, to increase total commitments of the facility up to $1.0 billion. |
• | On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, matures on July 30, 2020. |
• | On July 19, 2018, Fitch affirmed South Dakota Electric’s credit rating at A. |
• | On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. As of December 31, 2018, we have completed the divestiture of our oil and gas assets. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information. |
• | Corporate and Other, excluding tax reform impacts, decreased by approximately $37 million compared to the same period in the prior year driven primarily by a $27 million reduction of after-tax external acquisition and transition costs, a reduction of approximately $8.6 million of internal labor attributed to the SourceGas Acquisition and lower reallocated discontinued operation expenses of approximately $2.9 million, partially offset by a $4.4 million tax benefit in 2016; |
• | Gas Utilities’ earnings, excluding tax reform impacts, increased approximately $13 million, with a full year of earnings from our acquired SourceGas utilities compared to approximately 10.5 months in 2016; and a $4.1 million tax benefit recognized in 2017; |
• | We recorded a net tax benefit of approximately $8 million as a result of the revaluation of deferred tax balances due to the decrease in the statutory Federal income tax rate as a result of the TCJA. This benefit’s impact to our operating segments and Corporate and Other was: |
◦ | Electric Utilities - $23 million tax benefit |
◦ | Gas Utilities - $6.8 million tax expense |
◦ | Power Generation - $24 million tax benefit |
◦ | Mining - $2.7 million tax benefit |
◦ | Corporate and Other - $35 million tax expense consisting of $28 million of tax expense from the revaluation of Corporate deferred tax balances and $7 million of tax expense from the revaluation of deferred taxes that were originally recorded to AOCI. |
• | Electric Utilities’ earnings, excluding tax reform impacts, were comparable to the prior year reflecting an increase from returns on prior year generation investments, offset by higher employee costs and higher generation maintenance expenses; |
• | Earnings at our Power Generation segment, excluding tax reform impacts, decreased $3.5 million primarily due to an increase in net income attributable to noncontrolling interests, reflecting a full year in 2017 compared to approximately 8.5 months in 2016; and |
• | Earnings at our Mining segment, excluding tax reform impacts, increased approximately $1.6 million due to an increase in tons sold as a result of an extended outage in the prior year. |
• | In our Electric Utilities service territories, winter weather was mostly comparable to the prior year and the summer was milder in 2017 compared to the prior year. Heating degree days in 2017 were 3% lower than normal compared to 11% lower than normal in 2016. Cooling degree days for the full year of 2017 were 29% higher than normal compared to 14% higher than normal in 2016. |
• | On January 17, 2017, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 MW of renewable energy to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to acquire renewable energy resources to comply with the Colorado Renewable Energy Standard and presented the results to the CPUC on February 9, 2018. See the Electric Utilities 2018 highlights above for the outcome of this proposal. |
• | Construction was completed on the 144 mile transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017. |
• | On July 19, 2017, Wyoming Electric set a new summer load peak of 249 MW, exceeding the previous summer peak of 236 MW set in July 2016. |
• | Our service territories reported comparable year-over-year winter weather as measured by heating degree days compared to the 30-year average. Combined heating degree days for the full year in 2017 were 10% less than normal compared to 11% less than normal in the same period in 2016. |
• | During the fourth quarter of 2017, Arkansas Gas, Wyoming Gas and RMNG all filed rate review applications with their respective state commissions. See the Gas Utilities 2018 highlights above for the outcomes of these rate reviews. |
• | On August 4, 2017, we renewed the ATM equity offering program, which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. We did not issue any common shares during the twelve months ended December 31, 2017. |
• | 2017 credit rating updates: On December 12, 2017, Moody’s affirmed Black Hills’ credit rating at Baa2 with a Stable outlook. On October 4, 2017, Fitch affirmed Black Hills’ credit rating at BBB+ rating and maintained a Stable outlook, and on July 21, 2017, S&P affirmed Black Hills’ credit rating at BBB rating and maintained a Stable outlook. |
• | On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information. |
2018 | Variance | 2017 | Variance | 2016 | |||||||||||
Revenue (a) | $ | 711,451 | $ | 6,801 | $ | 704,650 | $ | 27,369 | $ | 677,281 | |||||
Total fuel and purchased power | 277,093 | 8,688 | 268,405 | 7,056 | 261,349 | ||||||||||
Gross margin (b) (c) (d) | 434,358 | (1,887 | ) | 436,245 | 20,313 | 415,932 | |||||||||
Operations and maintenance | 186,175 | 13,868 | 172,307 | 14,173 | 158,134 | ||||||||||
Depreciation and amortization | 98,639 | 5,324 | 93,315 | 8,670 | 84,645 | ||||||||||
Total operating expenses | 284,814 | 19,192 | 265,622 | 22,843 | 242,779 | ||||||||||
Operating income | 149,544 | (21,079 | ) | 170,623 | (2,530 | ) | 173,153 | ||||||||
Interest expense, net | (52,667 | ) | (393 | ) | (52,274 | ) | (1,983 | ) | (50,291 | ) | |||||
Other income (expense), net | (1,235 | ) | (2,965 | ) | 1,730 | (1,463 | ) | 3,193 | |||||||
Income tax expense (a) | (16,702 | ) | (6,705 | ) | (9,997 | ) | 30,231 | (40,228 | ) | ||||||
Net income (loss) available for common stock | $ | 78,940 | $ | (31,142 | ) | $ | 110,082 | $ | 24,255 | $ | 85,827 |
(a) | We estimated and recorded a reserve to revenue of approximately $22.3 million during year ended December 31, 2018 to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs. This reduction to revenues is offset by lower tax expense and has no impact on overall results. |
(b) | Non-GAAP measure. |
(c) | The year ended December 31, 2018 includes Horizon Point shared facility revenues of approximately $11 million, which are allocated to all of our operating segments as facility expenses. This shared facility agreement has no impact on BHC’s consolidated operating results. |
(d) | Gross margin was impacted for the year ended December 31, 2018 by ($4.3) million as a result of the Wyoming Electric PCA settlement. |
2018 | 2017 | 2016 | |
Regulated power plant fleet availability: | |||
Coal-fired plants (a) (b) | 93.9% | 88.9% | 90.2% |
Natural gas fired plants and Other plants | 96.4% | 96.1% | 95.1% |
Wind (c) | 96.9% | 93.3% | 79.3% |
Total availability | 95.6% | 93.6% | 93.5% |
Wind capacity factor | 39.2% | 36.7% | 36.6% |
(a) | 2017 reflects planned outages at Neil Simpson II, Wyodak, and Wygen II. |
(b) | 2016 reflects a planned outage at Wygen III, an extended planned outage at Wyodak and an unplanned outage at Neil Simpson II. |
(c) | 2017 and 2016 were lower due to the addition of Peak View Wind Project with ownership transfer in November, 2016. |
(in millions) | |||
TCJA revenue reserve | $ | (22.3 | ) |
Wyoming Electric PCA Stipulation | (2.6 | ) | |
Other | (0.6 | ) | |
Horizon Point shared facility revenue (b) | 9.8 | ||
Rider recovery | 5.1 | ||
Weather | 3.6 | ||
Power Marketing, ancillary wheeling and Tech Services | 3.5 | ||
Residential customer growth | 1.6 | ||
Total increase (decrease) in Gross margin (a) | $ | (1.9 | ) |
(a) | Non-GAAP measure |
(b) | Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results. |
(in millions) | |||
Peak View Wind Project return on investment | $ | 7.8 | |
Rider recovery | 7.4 | ||
Other (b) | 3.0 | ||
Commercial and industrial demand | 2.1 | ||
Total increase in Gross margin (a) | $ | 20.3 |
(a) | Non-GAAP measure |
(b) | Includes approximately 1.5 months of Horizon Point shared facility revenue. |
2018 | Variance | 2017 | Variance | 2016 | |||||||||||
Revenue: | |||||||||||||||
Natural gas - regulated (a) | $ | 942,924 | $ | 77,093 | $ | 865,831 | $ | 96,749 | $ | 769,082 | |||||
Other - non-regulated | 82,383 | 584 | 81,799 | 12,538 | 69,261 | ||||||||||
Total revenue | 1,025,307 | 77,677 | 947,630 | 109,287 | 838,343 | ||||||||||
Cost of natural gas sold: | |||||||||||||||
Natural gas - regulated | 442,530 | 61,271 | 381,259 | 65,641 | 315,618 | ||||||||||
Other - non-regulated | 19,623 | (8,721 | ) | 28,344 | (8,203 | ) | 36,547 | ||||||||
Total cost of natural gas sold | 462,153 | 52,550 | 409,603 | 57,438 | 352,165 | ||||||||||
Gross margin (b): | |||||||||||||||
Natural gas - regulated | 500,394 | 15,822 | 484,572 | 31,108 | 453,464 | ||||||||||
Other - non-regulated | 62,760 | 9,305 | 53,455 | 20,741 | 32,714 | ||||||||||
Total gross margin (b) | 563,154 | 25,127 | 538,027 | 51,849 | 486,178 | ||||||||||
Operations and maintenance | 291,481 | 22,291 | 269,190 | 23,364 | 245,826 | ||||||||||
Depreciation and amortization | 86,434 | 2,702 | 83,732 | 5,397 | 78,335 | ||||||||||
Total operating expenses | 377,915 | 24,993 | 352,922 | 28,761 | 324,161 | ||||||||||
Operating income | 185,239 | 134 | 185,105 | 23,088 | 162,017 | ||||||||||
Interest expense, net | (80,180 | ) | (1,605 | ) | (78,575 | ) | (3,562 | ) | (75,013 | ) | |||||
Other income (expense), net | (431 | ) | 398 | (829 | ) | (1,013 | ) | 184 | |||||||
Income tax expense (a) | 55,655 | 95,454 | (39,799 | ) | (12,337 | ) | (27,462 | ) | |||||||
Net income | 160,283 | 94,381 | 65,902 | 6,176 | 59,726 | ||||||||||
Net income attributable to noncontrolling interest | — | 107 | (107 | ) | (5 | ) | (102 | ) | |||||||
Net income available for common stock | $ | 160,283 | $ | 94,488 | $ | 65,795 | $ | 6,171 | $ | 59,624 |
(a) | We estimated and recorded a reserve to revenue of approximately $20.5 million during the year ended December 31, 2018 to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs. This reduction to revenues is offset by lower tax expense and has no impact on overall results. |
(b) | Non-GAAP measure. |
(in millions) | |||
Weather (b) | $ | 13.8 | |
New rates | 10.7 | ||
Customer growth - distribution | 5.2 | ||
Mark-to-market gains on non-utility natural gas commodity contracts | 4.0 | ||
Transport and transmission | 3.6 | ||
Natural gas volumes sold | 3.2 | ||
Non-utility - Choice Gas, Tech Services and appliance repair | 2.7 | ||
Other | 2.4 | ||
TCJA revenue reserve | (20.5 | ) | |
Total increase (decrease) in Gross margin (a) | $ | 25.1 |
(a) | Non-GAAP measure |
(b) | Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than the 30-year average (normal) compared to 10% lower than normal in 2017. |
(in millions) | |||
12 months of SourceGas utilities’ margins in 2017 compared to 10.5 months in 2016 | $ | 51.0 | |
Other | 0.8 | ||
Total increase (decrease) in Gross margin (a) | $ | 51.8 |
(a) | Non-GAAP measure |
2018 | Variance | 2017 | Variance | 2016 | |||||||||||
Revenue | $ | 88,952 | $ | (2,594 | ) | $ | 91,546 | $ | 415 | $ | 91,131 | ||||
Operations and maintenance | 33,727 | 1,345 | 32,382 | (254 | ) | 32,636 | |||||||||
Depreciation and amortization | 6,913 | 920 | 5,993 | 1,889 | 4,104 | ||||||||||
Total operating expenses | 40,640 | 2,265 | 38,375 | 1,635 | 36,740 | ||||||||||
Operating income | 48,312 | (4,859 | ) | 53,171 | (1,220 | ) | 54,391 | ||||||||
Interest expense, net | (4,995 | ) | (2,159 | ) | (2,836 | ) | (1,061 | ) | (1,775 | ) | |||||
Other income (expense), net | (53 | ) | 1 | (54 | ) | (56 | ) | 2 | |||||||
Income tax benefit (expense) | (8,267 | ) | (18,600 | ) | 10,333 | 27,462 | (17,129 | ) | |||||||
Net income | 34,997 | (25,617 | ) | 60,614 | 25,125 | 35,489 | |||||||||
Net income attributable to noncontrolling interest | (14,220 | ) | (85 | ) | (14,135 | ) | (4,576 | ) | (9,559 | ) | |||||
Net income available for common stock | $ | 20,777 | $ | (25,702 | ) | $ | 46,479 | 20,549 | $ | 25,930 |
2018 | 2017 | 2016 | |
Contracted fleet plant availability: | |||
Gas-fired plants | 99.4% | 99.2% | 99.2% |
Coal-fired plants (a) | 85.8% | 96.9% | 95.5% |
Total | 95.9% | 98.6% | 98.3% |
(a) | Wygen I experienced a planned outage in 2018. |
2018 | Variance | 2017 | Variance | 2016 | |||||||||||
Revenue | $ | 68,033 | $ | 1,412 | $ | 66,621 | $ | 6,341 | $ | 60,280 | |||||
Operations and maintenance | 43,728 | (1,154 | ) | 44,882 | 5,306 | 39,576 | |||||||||
Depreciation, depletion and amortization | 7,965 | (274 | ) | 8,239 | (1,107 | ) | 9,346 | ||||||||
Total operating expenses | 51,693 | (1,428 | ) | 53,121 | 4,199 | 48,922 | |||||||||
Operating income | 16,340 | 2,840 | 13,500 | 2,142 | 11,358 | ||||||||||
Interest expense, net | (536 | ) | (331 | ) | (205 | ) | 172 | (377 | ) | ||||||
Other income, net | 164 | (2,027 | ) | 2,191 | (18 | ) | 2,209 | ||||||||
Income tax benefit (expense) | (3,069 | ) | (1,969 | ) | (1,100 | ) | 2,037 | (3,137 | ) | ||||||
Net income available for common stock | $ | 12,899 | $ | (1,487 | ) | $ | 14,386 | $ | 4,333 | $ | 10,053 |
2018 | 2017 | 2016 | ||||
Tons of coal sold | 4,085 | 4,183 | 3,817 | |||
Cubic yards of overburden moved (a) | 8,970 | 9,018 | 7,916 | |||
Coal reserves at year-end | 189,164 | 194,909 | 199,905 |
(a) | Increase in overburden in 2018 and 2017 compared to 2016 was due to relocating mining operations to areas of the mine with higher overburden. |
(in thousands) | 2018 | Variance | 2017 | Variance | 2016 | ||||||||||
Operating (loss) (a) | $ | (2,398 | ) | $ | 3,265 | $ | (5,663 | ) | $ | 59,075 | $ | (64,738 | ) | ||
Other income (expense): | |||||||||||||||
Interest (expense) income, net (a) | (1,597 | ) | 1,615 | (3,212 | ) | 4,013 | (7,225 | ) | |||||||
Other income (expense), net | 375 | 1,305 | (930 | ) | 264 | (1,194 | ) | ||||||||
Income tax benefit (expense) | (3,950 | ) | 28,854 | (32,804 | ) | (61,659 | ) | 28,855 | |||||||
Net income (loss) available for common stock | $ | (7,570 | ) | $ | 35,039 | $ | (42,609 | ) | $ | 1,693 | $ | (44,302 | ) |
(a) | Includes certain general and administrative and interest expenses that are not reported as discontinued operations. |
• | Prior year tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances as a result of the TCJA; |
• | Higher current year state income tax expense of $4.6 million; |
• | A decrease in corporate expenses from prior year acquisition costs; and |
• | Lower interest costs due to interest expenses originally charged to our Oil and Gas Segment in 2017 which were not reclassified to discontinued operations in 2017, and were allocated to our operating segments in 2018. |
• | Tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances as a result of the TCJA; |
• | A decrease in after-tax acquisition and transition expenses of approximately $36 million, driven by lower external acquisition costs and lower internal labor attributed to the SourceGas Acquisition; |
• | As a result of the Oil and Gas segment being reported as discontinued operations in 2017, indirect operating costs that would have been charged to this segment were reallocated to other business segments in 2017. These same costs in 2016 are reported as Corporate and Other; |
• | A decrease of approximately $4.4 million in tax benefits; and |
• | A decrease in other corporate expenses. |
2018 | Variance | 2017 | Variance | 2016 | |||||||||||
Revenue | $ | 5,897 | $ | (19,485 | ) | $ | 25,382 | $ | (8,676 | ) | $ | 34,058 | |||
Operations and maintenance | 11,014 | (11,858 | ) | 22,872 | (4,315 | ) | 27,187 | ||||||||
Depreciation, depletion and amortization | 1,300 | (6,221 | ) | 7,521 | (5,989 | ) | 13,510 | ||||||||
Loss on sale of asset | 3,259 | 3,259 | — | — | — | ||||||||||
Impairment of long-lived assets | — | (20,385 | ) | 20,385 | (86,572 | ) | 106,957 | ||||||||
Total operating expenses | 15,573 | (35,205 | ) | 50,778 | (96,876 | ) | 147,654 | ||||||||
Operating (loss) | (9,676 | ) | 15,720 | (25,396 | ) | 88,200 | (113,596 | ) | |||||||
Interest income (expense), net | (19 | ) | (200 | ) | 181 | (517 | ) | 698 | |||||||
Other income (expense), net | 190 | 487 | (297 | ) | (407 | ) | 110 | ||||||||
Income tax benefit (expense) | 2,618 | (5,795 | ) | 8,413 | (40,213 | ) | 48,626 | ||||||||
(Loss) from discontinued operations available for common stock | $ | (6,887 | ) | $ | 10,212 | $ | (17,099 | ) | $ | 47,063 | $ | (64,162 | ) |
December 31, | ||||
Assumptions | Percentage Change | 2018 Increase/(Decrease) PBO/APBO (a) | 2019 Increase/(Decrease) Expense - Pretax | |
Pension | ||||
Discount rate (b) | +/- 0.5 | (25,221)/27,665 | (3,597)/3,906 | |
Expected return on assets | +/- 0.5 | N/A | (2,033)/2,035 | |
OPEB | ||||
Discount rate (b) | +/- 0.5 | (2,525)/2,743 | 89/(98) | |
Expected return on assets | +/- 0.5 | N/A | (38)/38 |
(a) | Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans. |
(b) | Impact on service cost, interest cost and amortization of gains or losses. |
Financial Position Summary | 2018 | 2017 | ||||
Cash and cash equivalents | $ | 20,776 | $ | 15,420 | ||
Restricted cash and equivalents | $ | 3,369 | $ | 2,820 | ||
Notes payable | $ | 185,620 | $ | 211,300 | ||
Short-term debt, including current maturities of long-term debt | $ | 5,743 | $ | 5,743 | ||
Long-term debt (a) | $ | 2,950,835 | $ | 3,109,400 | ||
Stockholders’ equity | $ | 2,181,588 | $ | 1,708,974 | ||
Ratios | ||||||
Long-term debt ratio | 57 | % | 64 | % | ||
Total debt ratio | 59 | % | 66 | % |
(a) | Carrying amount of long-term debt is net of deferred financing costs. |
(in millions) | 2018 | 2017 | 2016 |
Tax benefit | $— | $37 | $81 |
Purpose of Cash Collateral | 2018 | 2017 | ||||
Natural Gas Futures and Basis Swaps Pursuant to Utility Commission Approved Hedging Programs | $ | 7,266 | $ | 7,694 | ||
Natural Gas Over-the-Counter Swaps Pursuant to Master Agreements for Derivative Instruments | — | 562 | ||||
Total Cash Collateral | $ | 7,266 | $ | 8,256 |
Current | Revolver Borrowings at | CP Program Borrowings at | Letters of Credit at | Available Capacity at | ||||||||||||
Credit Facility | Expiration | Capacity | December 31, 2018 | December 31, 2018 | December 31, 2018 | December 31, 2018 | ||||||||||
Revolving Credit Facility | July 30, 2023 | $ | 750 | $ | — | $ | 186 | $ | 22 | $ | 542 |
(dollars in millions) | |||
Maximum amount outstanding - commercial paper (based on daily outstanding balances) | $ | 231 | |
Maximum amount outstanding - revolving credit facility (based on daily outstanding balances) | $ | — | |
Average amount outstanding - commercial paper (based on daily outstanding balances) (a) | $ | 120 | |
Average amount outstanding - revolving credit facility (based on daily outstanding balances) | $ | — | |
Weighted average interest rates - commercial paper | 1.97 | % | |
Weighted average interest rates - revolving credit facility | — | % |
(a) | No commercial paper was issued from November 1, 2018 to December 11, 2018 due to excess cash on hand from the Equity Units settlement until we paid off the $250 million, 2.5% Senior unsecured notes due January 11, 2019. |
• | Short-term borrowings from our CP Program. |
• | On December 12, 2018, we paid off the $250 million, 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to repay this obligation. |
• | On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued November 23, 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. See Note 12 for more information. |
• | On August 17, 2018, we completed a public debt offering of $400 million principal amount, 4.350% senior unsecured notes due 2033. The proceeds were used to repay the $299 million principal amount of our RSNs due 2028 and pay down short-term debt. Through this offering, we successfully remarketed the $299 million principal amount of the existing subordinated notes, which were originally issued as a part of the Company's Equity Units on November 23, 2015. See Note 6 for more information. |
• | On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, will now mature July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. See Note 6 for more information. |
• | We did not issue any shares of common stock under our ATM equity offering program in 2018. |
2018 | 2017 | 2016 | |
Dividend Payout Ratio | 40% | 50% | 65% |
Dividends Per Share | $1.93 | $1.81 | $1.68 |
Borrowings From Money Pool Outstanding | ||||||
Subsidiary | 2018 | 2017 | ||||
Black Hills Utility Holdings | $ | 48,056 | $ | 35,693 | ||
South Dakota Electric | 38,690 | 13,397 | ||||
Wyoming Electric | 24,704 | 15,290 | ||||
Total Money Pool borrowings from Parent | $ | 111,450 | $ | 64,380 |
2018 | 2017 | 2016 | |||||||
Cash provided by (used in) | |||||||||
Operating activities | $ | 488,811 | $ | 428,261 | $ | 320,479 | |||
Investing activities | $ | (465,849 | ) | $ | (317,118 | ) | $ | (1,588,165 | ) |
Financing activities | $ | (17,057 | ) | $ | (108,695 | ) | $ | 840,998 |
• | Cash earnings (income from continuing operations plus non-cash adjustments) were $7 million lower than prior year driven primarily by impacts of customer refunds related to the TCJA tax decrease which lowered current year revenue; |
• | Net inflow from operating assets and liabilities was $62 million higher than prior year, primarily attributable to: |
• | Cash inflows increased by approximately $34 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of energy commodity prices on our accounts payable, partially offset by the expiration of accrued contract payables related to Equity Units; |
• | Cash outflows increased by approximately $43 million compared to the prior year as a result of higher accounts receivable driven by higher revenues, energy delivered and energy commodity prices; and |
• | Cash inflows increased by approximately $72 million primarily as a result of changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity price on our regulatory assets and from an increase in current regulatory liabilities driven by cash collections of income taxes from customer bills in excess of current tax rates subsequent to the TCJA that will be refunded in the future; |
• | Cash outflows decreased by approximately $15 million due to additional pension contributions made in the prior year; |
• | Cash inflows increased approximately $15 million for other operating activities compared to the prior year primarily due to the long-term expiration of accrued contract payables related to Equity Units; and |
• | Cash outflows increased approximately $25 million due to operating activities of discontinued operations. |
• | Capital expenditures of approximately $458 million in 2018 compared to $326 million in 2017. The $132 million increase from the prior year was due to higher capital expenditures at our Electric and Gas Utilities which included additional transmission investments, and higher programmatic integrity capital at our Gas Utilities. Capital expenditures increased at our Power Generation segment due to the Busch Ranch I purchase, and from investments made to Wygen I. Capital investments also increased at our Mining segment as they purchased a new mining shovel in 2018. |
• | A $24 million investment partially offset by a $13 million increase in net cash provided by investing activities from discontinued operations. |
• | Payments of long-term debt increased by $749 million due to current year payments on the $300 million term loan refinanced in July 2018, the retirement of $299 million of RSNs in August 2018 and the retirement of $250 million Senior unsecured notes in December 2018, compared to $100 million of principal payments made on term loans in the prior year; |
• | Long-term borrowings increased by $700 million due to the issuance of $400 million senior secured notes in August 2018 and the refinancing of our $300 million unsecured term loan in July 2018; |
• | Gross proceeds of approximately $299 million received in exchange for approximately 6.372 million shares of common stock from the Equity Unit conversion; |
• | Net short-term debt payments increased by $140 million as a result of using proceeds from the Equity Unit conversion to pay down short-term debt; |
• | Cash dividends on common stock of $107 million were paid in 2018 compared to $97 million paid in 2017; |
• | Cash outflows for other financing activities increased by approximately $4.3 million driven primarily by higher financing costs incurred in the July 30, 2018 and August 17, 2018 debt transactions. |
• | Cash earnings (income from continuing operations plus non-cash adjustments) were $68 million higher than prior year; |
• | Net outflow from operating assets and liabilities was $16 million lower than prior year, primarily attributable to: |
• | Cash outflows decreased by approximately $4.8 million as a result of changes in accounts payable and accrued liabilities driven by changes in working capital requirements; |
• | Cash outflows decreased by approximately $20 million compared to the prior year as a result of lower accounts receivable due to warmer weather partially offset by higher natural gas inventory; and |
• | Cash outflows increased by approximately $9.5 million primarily as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts compared to the same period in the prior year; |
• | Cash outflows decreased by approximately $29 million as a result of interest rate swap settlements; |
• | Cash outflows increased by approximately $14 million due to additional pension contributions made in 2017; |
• | Cash outflows increased approximately $7.8 million for other operating activities compared to the prior year; and |
• | Cash inflows decreased approximately $17 million due to operating activities of discontinued operations. |
• | In 2016 cash outflows included approximately $1.1 billion for the acquisition of SourceGas, net of $760 million long-term debt assumed (see Note 2 in Item 8 of Part II of this Annual Report on Form 10-K); |
• | Capital expenditures of approximately $326 million in 2017 compared to $455 million in 2016. The $129 million variance to the prior year was due primarily to higher prior year capital expenditures at our Electric Utilities from generation investments at Colorado Electric; and |
• | Cash inflows increased approximately $16 million due to investing activities of discontinued operations. |
• | Long-term borrowings decreased by $1.8 billion due to the 2016 financings which consisted of $693 million of net proceeds from the August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, $500 million of proceeds from the August 9, 2016 term loan, $546 million of net proceeds from our January 13, 2016 public debt offering used to partially finance the SourceGas Acquisition and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract; |
• | Payments on long-term debt decreased by $1.1 billion due to the 2016 refinancing of the $760 million of long-term debt assumed in the SourceGas Acquisition and lower current year payments on term loans, $106 million paid on term loans in 2017 compared to $400 million paid on term loans in 2016; |
• | Proceeds of $216 million from the sale of a 49.9% noncontrolling interest of Black Hills Colorado IPP that took place in 2016 (see Note 12 in Item 8 of Part II of this Annual Report on Form 10-K); |
• | Proceeds from common stock issuances decreased by $117 million primarily from issuing common stock under our ATM equity offering program in 2016; |
• | Net short-term borrowings increased by $95 million primarily due to CP borrowings used to pay down long-term debt; |
• | Cash dividends on common stock of $97 million were paid in 2017 compared to $88 million paid in 2016; |
• | In 2017, distributions to noncontrolling interests increased by $8.8 million compared to 2016; and |
• | Cash outflows for other financing activities decreased by approximately $16 million driven primarily by higher financing costs from the 2016 debt offerings and refinancings compared to a payment of $5.6 million for a redeemable noncontrolling interest in March 2017. |
2018 | 2017 | 2016 | |||||||||
Property additions: (a) | |||||||||||
Electric Utilities | $ | 152,524 | $ | 138,060 | $ | 258,739 | |||||
Gas Utilities | 288,438 | 184,389 | 173,930 | ||||||||
Power Generation | 30,945 | 1,864 | 4,719 | ||||||||
Mining | 18,794 | 6,708 | 5,709 | ||||||||
Corporate and Other | 11,723 | 6,668 | 17,353 | ||||||||
Capital expenditures before discontinued operations | 502,424 | 337,689 | 460,450 | ||||||||
Discontinued operations | 2,402 | 23,222 | 6,669 | ||||||||
Total capital expenditures | 504,826 | 360,911 | 467,119 | ||||||||
Common stock dividends | 106,591 | 96,744 | 87,570 | ||||||||
Maturities/redemptions of long-term debt | 854,743 | 105,743 | 1,164,308 | ||||||||
Total capital requirements | $ | 1,466,160 | $ | 563,398 | $ | 1,718,997 |
(a) | Includes accruals for property, plant and equipment. |
Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a) | BBB+ | Stable |
Moody’s (b) | Baa2 | Stable |
Fitch (c) | BBB+ | Stable |
(a) | On August 9, 2018, S&P upgraded to BBB+ rating and revised the outlook to Stable. |
(b) | On December 12, 2018, Moody's affirmed Baa2 rating and maintained a Stable outlook. |
(c) | On October 11, 2018, Fitch affirmed BBB+ rating and maintained a Stable outlook. |
Rating Agency | Senior Secured Rating |
S&P (a) | A |
Moody’s (b) | A1 |
Fitch (c) | A |
(a) | On August 9, 2018, S&P upgraded to A rating. |
(b) | On December 12, 2018, Moody’s affirmed A1 rating. |
(c) | On October 11, 2018, Fitch affirmed A rating. |
Payments Due by Period | |||||||||||||||
Contractual Obligations | Total | Less Than 1 Year | 1-3 Years | 4-5 Years | After 5 Years | ||||||||||
Long-term debt(a)(b) | $ | 2,982,776 | $ | 5,743 | $ | 514,178 | $ | 525,000 | $ | 1,937,855 | |||||
Unconditional purchase obligations(c) | 737,507 | 151,110 | 259,073 | 178,961 | 148,363 | ||||||||||
Operating lease obligations(d) | 4,076 | 1,052 | 808 | 440 | 1,776 | ||||||||||
Other long-term obligations(e) | 56,800 | — | — | — | 56,800 | ||||||||||
Employee benefit plans(f) | 138,510 | 18,144 | 56,684 | 38,315 | 25,367 | ||||||||||
Liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions | 3,583 | — | — | — | 3,583 | ||||||||||
CP Program | 185,620 | 185,620 | — | — | — | ||||||||||
Total contractual cash obligations(g) | $ | 4,108,872 | $ | 361,669 | $ | 830,743 | $ | 742,716 | $ | 2,173,744 |
(a) | Long-term debt amounts do not include discounts or premiums on debt. |
(b) | The following amounts are estimated for interest payments over the next five years which are not included within the long-term debt balances presented: $130 million in 2019, $126 million in 2020, $108 million in 2021, $108 million in 2022 and $102 million in 2023. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2018. |
(c) | Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas transportation and storage agreements. The energy charges under the PPAs are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2018 and price assumptions using existing prices at December 31, 2018. Our transmission obligations are based on filed tariffs as of December 31, 2018. |
(d) | Includes operating leases associated with several office buildings, warehouses and call centers, equipment and vehicles. |
(e) | Includes estimated asset retirement obligations associated with our Electric Utilities, Gas Utilities and Mining segments as discussed in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. |
(f) | Represents both estimated employer contributions to Defined Benefit Pension Plan and payments to employees for the Non-Pension Defined Benefit Postretirement Healthcare Plans and the Supplemental Non-Qualified Defined Benefit Plans through the year 2028. |
(g) | Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including commodity related contracts that have a negative fair value at December 31, 2018. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; and (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table. |
Outstanding at | Year | |||
Nature of Guarantee | December 31, 2018 | Expiring | ||
Indemnification for subsidiary reclamation/surety bonds (a) | $ | 54,683 | Ongoing | |
Contract performance guarantee (b) | 39,807 | December 2019 | ||
$ | 94,490 |
(a) | We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets. |
(b) | BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of the Busch Ranch II Wind Farm. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations. The guarantee decreases as progress payments are made. |
• | Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, market speculation, pipeline constraints, and other factors that may impact natural gas supply and demand; |
• | Interest rate risk associated with our variable debt as described in Notes 6 and 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
2018 | 2017 | ||||||
Net derivative (liabilities) assets | $ | (2,214 | ) | $ | (6,644 | ) | |
Cash collateral | 7,266 | 8,256 | |||||
$ | 5,052 | $ | 1,612 |
2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | Total | |||||||||||||||
Long-term debt | |||||||||||||||||||||
Fixed rate(a) | $ | 5,743 | $ | 205,743 | $ | 1,435 | $ | — | $ | 525,000 | $ | 1,925,000 | $ | 2,662,921 | |||||||
Average interest rate | 2.32 | % | 5.78 | % | 2.32 | % | — | % | 4.25 | % | 3.53 | % | 4.5 | % | |||||||
Variable rate | $ | — | $ | 300,000 | $ | 7,000 | $ | — | $ | — | $ | 12,855 | $ | 319,855 | |||||||
Average interest rate (b) | — | % | 3.16 | % | 1.73 | % | — | % | — | % | 1.77 | % | 3.07 | % | |||||||
Total long-term debt | $ | 5,743 | $ | 505,743 | $ | 8,435 | $ | — | $ | 525,000 | $ | 1,937,855 | $ | 2,982,776 | |||||||
Average interest rate (b) | 2.32 | % | 4.22 | % | 1.83 | % | — | % | 4.25 | % | 3.52 | % | 4.34 | % |
(a) | Excludes unamortized premium or discount. |
(b) | Interest rates as of December 31, 2018. |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Management’s Report on Internal Controls Over Financial Reporting | |
Reports of Independent Registered Public Accounting Firm | |
Consolidated Statements of Income for the three years ended December 31, 2018 | |
Consolidated Statements of Comprehensive Income for the three years ended December 31, 2018 | |
Consolidated Balance Sheets as of December 31, 2018 and 2017 | |
Consolidated Statements of Cash Flows for the three years ended December 31, 2018 | |
Consolidated Statements of Equity for the three years ended December 31, 2018 | |
Notes to Consolidated Financial Statements |
Year ended | December 31, 2018 | December 31, 2017 | December 31, 2016 | ||||||
(in thousands, except per share amounts) | |||||||||
Revenue | $ | 1,754,268 | $ | 1,680,266 | $ | 1,538,916 | |||
Operating expenses: | |||||||||
Fuel, purchased power and cost of natural gas sold | 625,610 | 563,288 | 499,132 | ||||||
Operations and maintenance | 481,706 | 454,605 | 426,603 | ||||||
Depreciation, depletion and amortization | 196,328 | 188,246 | 175,533 | ||||||
Taxes - property and production | 51,746 | 51,578 | 46,160 | ||||||
Other operating expenses | 1,841 | 5,813 | 55,307 | ||||||
Total operating expenses | 1,357,231 | 1,263,530 | 1,202,735 | ||||||
Operating income | 397,037 | 416,736 | 336,181 | ||||||
Other income (expense): | |||||||||
Interest charges - | |||||||||
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | (143,720 | ) | (140,533 | ) | (139,091 | ) | |||
Allowance for funds used during construction - borrowed | 2,104 | 2,415 | 2,981 | ||||||
Interest income | 1,641 | 1,016 | 1,429 | ||||||
Allowance for funds used during construction - equity | 619 | 2,321 | 3,270 | ||||||
Other income (expense), net | (1,799 | ) | (213 | ) | 1,124 | ||||
Total other income (expense) | (141,155 | ) | (134,994 | ) | (130,287 | ) | |||
Income before income taxes | 255,882 | 281,742 | 205,894 | ||||||
Income tax benefit (expense) | 23,667 | (73,367 | ) | (59,101 | ) | ||||
Income from continuing operations | 279,549 | 208,375 | 146,793 | ||||||
Net (loss) from discontinued operations | (6,887 | ) | (17,099 | ) | (64,162 | ) | |||
Net income | 272,662 | 191,276 | 82,631 | ||||||
Net income attributable to noncontrolling interest | (14,220 | ) | (14,242 | ) | (9,661 | ) | |||
Net income available for common stock | $ | 258,442 | $ | 177,034 | $ | 72,970 | |||
Amounts attributable to common shareholders: | |||||||||
Net income from continuing operations | $ | 265,329 | $ | 194,133 | $ | 137,132 | |||
Net (loss) from discontinued operations | (6,887 | ) | (17,099 | ) | (64,162 | ) | |||
Net income (loss) available for common stock | $ | 258,442 | $ | 177,034 | $ | 72,970 | |||
Earnings (loss) per share of common stock, Basic - | |||||||||
Earnings from continuing operations | $ | 4.88 | $ | 3.65 | $ | 2.64 | |||
(Loss) from discontinued operations | (0.13 | ) | (0.32 | ) | (1.23 | ) | |||
Total earnings per share of common stock, Basic | $ | 4.75 | $ | 3.33 | $ | 1.41 | |||
Earnings (loss) per share of common stock, Diluted - | |||||||||
Earnings from continuing operations | $ | 4.78 | $ | 3.52 | $ | 2.57 | |||
(Loss) from discontinued operations | (0.12 | ) | (0.31 | ) | (1.20 | ) | |||
Total earnings per share of common stock, Diluted | $ | 4.66 | $ | 3.21 | $ | 1.37 | |||
Weighted average common shares outstanding: | |||||||||
Basic | 54,420 | 53,221 | 51,922 | ||||||
Diluted | 55,486 | 55,120 | 53,271 |
Year ended | December 31, 2018 | December 31, 2017 | December 31, 2016 | ||||||
(in thousands) | |||||||||
Net income | $ | 272,662 | $ | 191,276 | $ | 82,631 | |||
Other comprehensive income (loss), net of tax: | |||||||||
Benefit plan liability adjustments - net gain (loss) (net of tax of $(660), $1,030 and $757, respectively) | 2,155 | (1,890 | ) | (1,738 | ) | ||||
Benefit plan liability adjustments - prior service (costs) (net of tax of $0, $0 and $107, respectively) | — | — | (247 | ) | |||||
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(586), $(585) and $(600), respectively) | 1,901 | 1,072 | 1,378 | ||||||
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $43, $69 and $67, respectively) | (135 | ) | (128 | ) | (154 | ) | |||
Derivative instruments designated as cash flow hedges: | |||||||||
Net unrealized gains (losses) on interest rate swaps (net of tax of $0, $0 and $10,920, respectively) | — | — | (20,302 | ) | |||||
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(599), $(1,029) and $(1,365), respectively) | 2,252 | 1,912 | 2,534 | ||||||
Net unrealized gains (losses) on commodity derivatives (net of tax of $(228), $(135) and $212, respectively) | 755 | 231 | (361 | ) | |||||
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(31), $154 and $4,067, respectively) | 99 | (516 | ) | (6,938 | ) | ||||
Other comprehensive income (loss), net of tax | 7,027 | 681 | (25,828 | ) | |||||
Comprehensive income | 279,689 | 191,957 | 56,803 | ||||||
Less: comprehensive income attributable to non-controlling interest | (14,220 | ) | (14,242 | ) | (9,661 | ) | |||
Comprehensive income available for common stock | $ | 265,469 | $ | 177,715 | $ | 47,142 |
As of | ||||||
December 31, 2018 | December 31, 2017 | |||||
(in thousands) | ||||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 20,776 | $ | 15,420 | ||
Restricted cash and equivalents | 3,369 | 2,820 | ||||
Accounts receivable, net | 269,153 | 248,330 | ||||
Materials, supplies and fuel | 117,299 | 113,283 | ||||
Derivative assets, current | 1,500 | 304 | ||||
Income tax receivable, net | 12,978 | — | ||||
Regulatory assets, current | 48,776 | 81,016 | ||||
Other current assets | 29,982 | 25,367 | ||||
Current assets held for sale | — | 84,242 | ||||
Total current assets | 503,833 | 570,782 | ||||
Investments | 41,013 | 13,090 | ||||
Property, plant and equipment | 6,000,015 | 5,567,518 | ||||
Less accumulated depreciation and depletion | (1,145,136 | ) | (1,026,088 | ) | ||
Total property, plant and equipment, net | 4,854,879 | 4,541,430 | ||||
Other assets: | ||||||
Goodwill | 1,299,454 | 1,299,454 | ||||
Intangible assets, net | 14,337 | 7,559 | ||||
Regulatory assets, non-current | 235,459 | 216,438 | ||||
Other assets, non-current | 14,352 | 10,149 | ||||
Total other assets, non-current | 1,563,602 | 1,533,600 | ||||
TOTAL ASSETS | $ | 6,963,327 | $ | 6,658,902 |
As of | ||||||
December 31, 2018 | December 31, 2017 | |||||
(in thousands, except share amounts) | ||||||
LIABILITIES AND EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 210,609 | $ | 160,887 | ||
Accrued liabilities | 215,501 | 219,462 | ||||
Derivative liabilities, current | 947 | 2,081 | ||||
Accrued income tax, net | — | 1,022 | ||||
Regulatory liabilities, current | 29,810 | 6,832 | ||||
Notes payable | 185,620 | 211,300 | ||||
Current maturities of long-term debt | 5,743 | 5,743 | ||||
Current liabilities held for sale | — | 41,774 | ||||
Total current liabilities | 648,230 | 649,101 | ||||
Long-term debt, net of current maturities | 2,950,835 | 3,109,400 | ||||
Deferred credits and other liabilities: | ||||||
Deferred income tax liabilities, net | 311,331 | 336,520 | ||||
Regulatory liabilities, non-current | 510,984 | 478,294 | ||||
Benefit plan liabilities | 145,147 | 159,646 | ||||
Other deferred credits and other liabilities | 109,377 | 105,735 | ||||
Total deferred credits and other liabilities | 1,076,839 | 1,080,195 | ||||
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20) | ||||||
Equity: | ||||||
Stockholders’ equity - | ||||||
Common stock $1 par value; 100,000,000 shares authorized; issued: 60,048,567 and 53,579,986, respectively | 60,049 | 53,580 | ||||
Additional paid-in capital | 1,450,569 | 1,150,285 | ||||
Retained earnings | 700,396 | 548,617 | ||||
Treasury stock at cost - 44,253 and 39,064, respectively | (2,510 | ) | (2,306 | ) | ||
Accumulated other comprehensive income (loss) | (26,916 | ) | (41,202 | ) | ||
Total stockholders’ equity | 2,181,588 | 1,708,974 | ||||
Noncontrolling interest | 105,835 | 111,232 | ||||
Total equity | 2,287,423 | 1,820,206 | ||||
TOTAL LIABILITIES AND TOTAL EQUITY | $ | 6,963,327 | $ | 6,658,902 |
Year ended | December 31, 2018 | December 31, 2017 | December 31, 2016 | ||||||
(in thousands) | |||||||||
Operating activities: | |||||||||
Net income | $ | 272,662 | $ | 191,276 | $ | 82,631 | |||
Loss from discontinued operations, net of tax | 6,887 | 17,099 | 64,162 | ||||||
Income (loss) from continuing operations | 279,549 | 208,375 | 146,793 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||
Depreciation, depletion and amortization | 196,328 | 188,246 | 175,533 | ||||||
Deferred financing cost amortization | 7,845 | 8,261 | 6,180 | ||||||
Stock compensation | 12,390 | 7,626 | 10,885 | ||||||
Deferred income taxes | (24,239 | ) | 80,992 | 82,704 | |||||
Employee benefit plans | 14,068 | 10,141 | 14,291 | ||||||
Other adjustments, net | 5,836 | (4,773 | ) | (5,519 | ) | ||||
Change in certain operating assets and liabilities: | |||||||||
Materials, supplies and fuel | (2,919 | ) | (10,089 | ) | 1,211 | ||||
Accounts receivable and other current assets | (45,966 | ) | 4,534 | (27,172 | ) | ||||
Accounts payable and other current liabilities | 5,305 | (28,222 | ) | (33,023 | ) | ||||
Regulatory assets | 33,608 | (15,407 | ) | 3,614 | |||||
Regulatory liabilities | 18,533 | (4,536 | ) | (14,082 | ) | ||||
Contributions to defined benefit pension plans | (12,700 | ) | (27,700 | ) | (14,200 | ) | |||
Interest rate swap settlement | — | — | (28,820 | ) | |||||
Other operating activities, net | 6,689 | (8,418 | ) | (660 | ) | ||||
Net cash provided by operating activities of continuing operations | 494,327 | 409,030 | 317,735 | ||||||
Net cash provided by (used in) operating activities of discontinued operations | (5,516 | ) | 19,231 | 2,744 | |||||
Net cash provided by operating activities | 488,811 | 428,261 | 320,479 | ||||||
Investing activities: | |||||||||
Property, plant and equipment additions | (457,524 | ) | (326,010 | ) | (454,952 | ) | |||
Acquisition of net assets, net of long-term debt assumed | — | — | (1,124,238 | ) | |||||
Purchase of investment | (24,429 | ) | — | — | |||||
Other investing activities | (4,281 | ) | 1,011 | (562 | ) | ||||
Net cash (used in) investing activities of continuing operations | (486,234 | ) | (324,999 | ) | (1,579,752 | ) | |||
Net cash provided by (used in) investing activities of discontinued operations | 20,385 | 7,881 | (8,413 | ) | |||||
Net cash (used in) investing activities | (465,849 | ) | (317,118 | ) | (1,588,165 | ) | |||
Financing activities: | |||||||||
Dividends paid on common stock | (106,591 | ) | (96,744 | ) | (87,570 | ) | |||
Common stock issued | 300,834 | 4,408 | 121,619 | ||||||
Net increase (decrease) in commercial paper and short-term borrowings | (25,680 | ) | 114,700 | 19,800 | |||||
Long-term debt - issuance | 700,000 | — | 1,767,608 | ||||||
Long-term debt - repayments | (854,743 | ) | (105,743 | ) | (1,164,308 | ) | |||
Sale of noncontrolling interest | — | — | 216,370 | ||||||
Distributions to noncontrolling interests | (19,617 | ) | (18,397 | ) | (9,561 | ) | |||
Other financing activities | (11,260 | ) | (6,919 | ) | (22,960 | ) | |||
Net cash provided by (used in) financing activities | (17,057 | ) | (108,695 | ) | 840,998 | ||||
Net change in cash, restricted cash and cash equivalents | 5,905 | 2,448 | (426,688 | ) | |||||
Cash, restricted cash and cash equivalents beginning of year | 18,240 | 15,792 | 442,480 | ||||||
Cash, restricted cash and cash equivalents end of year | $ | 24,145 | $ | 18,240 | $ | 15,792 |
Common Stock | Treasury Stock | ||||||||||||||||||||||||
(in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non controlling Interest | Total | ||||||||||||||||
Balance at December 31, 2015 | 51,231,861 | $ | 51,232 | 39,720 | $ | (1,888 | ) | $ | 953,044 | $ | 472,534 | $ | (9,055 | ) | $ | — | $ | 1,465,867 | |||||||
Net income (loss) available for common stock | — | — | — | — | — | 72,970 | — | 9,661 | 82,631 | ||||||||||||||||
Other comprehensive income (loss), net of tax | — | — | — | — | — | — | (25,828 | ) | — | (25,828 | ) | ||||||||||||||
Dividends on common stock | — | — | — | — | — | (87,570 | ) | — | — | (87,570 | ) | ||||||||||||||
Share-based compensation | 145,634 | 146 | (16,165 | ) | 668 | 4,665 | — | — | — | 5,479 | |||||||||||||||
Issuance of common stock | 1,968,738 | 1,969 | — | — | 118,021 | — | — | — | 119,990 | ||||||||||||||||
Issuance costs | — | — | — | — | (1,566 | ) | — | — | — | (1,566 | ) | ||||||||||||||
Dividend reinvestment and stock purchase plan | 51,234 | 50 | — | — | 2,933 | — | — | — | 2,983 | ||||||||||||||||
Other stock transactions | — | — | (8,297 | ) | 429 | 47 | — | — | — | 476 | |||||||||||||||
Sale of noncontrolling interest | — | — | — | — | 61,838 | — | — | 115,395 | 177,233 | ||||||||||||||||
Distributions to noncontrolling interest | — | — | — | — | — | — | — | (9,561 | ) | (9,561 | ) | ||||||||||||||
Balance at December 31, 2016 | 53,397,467 | $ | 53,397 | 15,258 | $ | (791 | ) | $ | 1,138,982 | $ | 457,934 | $ | (34,883 | ) | $ | 115,495 | $ | 1,730,134 | |||||||
Net income (loss) available for common stock | — | — | — | — | — | 177,034 | — | 14,242 | 191,276 | ||||||||||||||||
Other comprehensive income (loss), net of tax | — | — | — | — | — | — | 681 | — | 681 | ||||||||||||||||
Reclassification of certain tax effects from AOCI | — | — | — | — | — | 7,000 | (7,000 | ) | — | — | |||||||||||||||
Dividends on common stock | — | — | — | — | — | (96,744 | ) | — | — | (96,744 | ) | ||||||||||||||
Share-based compensation | 134,266 | 134 | 23,806 | (1,515 | ) | 8,948 | — | — | — | 7,567 | |||||||||||||||
Tax effect of share-based compensation | — | — | — | — | 533 | 3,184 | — | — | 3,717 | ||||||||||||||||
Issuance costs | — | — | — | — | (189 | ) | — | — | — | (189 | ) | ||||||||||||||
Dividend reinvestment and stock purchase plan | 48,253 | 49 | — | — | 3,107 | — | — | — | 3,156 | ||||||||||||||||
Redemption of and distributions to noncontrolling interest | — | — | — | — | (1,096 | ) | 209 | — | (18,505 | ) | (19,392 | ) | |||||||||||||
Balance at December 31, 2017 | 53,579,986 | $ | 53,580 | 39,064 | $ | (2,306 | ) | $ | 1,150,285 | $ | 548,617 | $ | (41,202 | ) | $ | 111,232 | $ | 1,820,206 | |||||||
Net income (loss) available for common stock | — | — | — | — | — | 258,442 | — | 14,220 | 272,662 | ||||||||||||||||
Other comprehensive income (loss), net of tax | — | — | — | — | — | — | 7,027 | — | 7,027 | ||||||||||||||||
Reclassification of certain tax effects from AOCI | — | — | — | — | — | — | 740 | — | 740 | ||||||||||||||||
Reclassification to regulatory asset | — | — | — | — | — | — | 6,519 | — | 6,519 | ||||||||||||||||
Dividends on common stock | — | — | — | — | — | (106,591 | ) | — | — | (106,591 | ) | ||||||||||||||
Share-based compensation | 92,830 | 93 | 5,189 | (204 | ) | 7,301 | — | — | — | 7,190 | |||||||||||||||
Issuance of common stock | 6,371,690 | 6,372 | — | — | 292,628 | — | — | — | 299,000 | ||||||||||||||||
Issuance costs | — | — | — | — | (15 | ) | — | — | — | (15 | ) | ||||||||||||||
Dividend reinvestment and stock purchase plan | 4,061 | 4 | — | — | 216 | — | — | — | 220 | ||||||||||||||||
Other stock transactions | — | — | — | — | 154 | (72 | ) | — | — | 82 | |||||||||||||||
Distributions to noncontrolling interest | — | — | — | — | — | — | — | (19,617 | ) | (19,617 | ) | ||||||||||||||
Balance at December 31, 2018 | 60,048,567 | $ | 60,049 | 44,253 | $ | (2,510 | ) | $ | 1,450,569 | $ | 700,396 | $ | (26,916 | ) | $ | 105,835 | $ | 2,287,423 |
(1) | BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES |
2018 | Accounts Receivable, Trade | Unbilled Revenue | Less Allowance for Doubtful Accounts | Accounts Receivable, net | ||||||||
Electric Utilities | $ | 39,721 | $ | 35,125 | $ | (448 | ) | $ | 74,398 | |||
Gas Utilities | 96,123 | 90,521 | (2,592 | ) | 184,052 | |||||||
Power Generation | 1,876 | — | — | 1,876 | ||||||||
Mining | 3,988 | — | — | 3,988 | ||||||||
Corporate | 5,008 | — | (169 | ) | 4,839 | |||||||
Total | $ | 146,716 | $ | 125,646 | $ | (3,209 | ) | $ | 269,153 |
2017 | Accounts Receivable, Trade | Unbilled Revenue | Less Allowance for Doubtful Accounts | Accounts Receivable, net | ||||||||
Electric Utilities | $ | 39,347 | $ | 36,384 | $ | (586 | ) | $ | 75,145 | |||
Gas Utilities | 81,256 | 88,967 | (2,495 | ) | 167,728 | |||||||
Power Generation | 1,196 | — | — | 1,196 | ||||||||
Mining | 2,804 | — | — | 2,804 | ||||||||
Corporate | 1,457 | — | — | 1,457 | ||||||||
Total | $ | 126,060 | $ | 125,351 | $ | (3,081 | ) | $ | 248,330 |
Balance at Beginning of Year | Adjustments (a) | Additions Charged to Costs and Expenses | Recoveries and Other Additions | Write-offs and Other Deductions | Balance at End of Year | |||||||||||||||||||
2018 | $ | 3,081 | $ | — | $ | 6,859 | $ | 4,092 | $ | (10,823 | ) | $ | 3,209 | |||||||||||
2017 | $ | 2,392 | $ | — | $ | 4,926 | $ | 8,262 | $ | (12,499 | ) | $ | 3,081 | |||||||||||
2016 | $ | 1,741 | $ | 2,158 | $ | 2,704 | $ | 4,915 | $ | (9,126 | ) | $ | 2,392 |
• | Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs. |
• | Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, Black |
• | Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered. |
• | Other non-regulated services - Our Gas and Electric Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. |
Year ended December 31, 2018 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total | ||||||||||||
Customer types: | (in thousands) | |||||||||||||||||
Retail | $ | 594,329 | $ | 833,379 | $ | — | $ | 65,803 | $ | (32,194 | ) | $ | 1,461,317 | |||||
Transportation | — | 140,705 | — | — | (1,348 | ) | 139,357 | |||||||||||
Wholesale | 33,687 | — | 52,396 | — | (46,562 | ) | 39,521 | |||||||||||
Market - off-system sales | 24,799 | 866 | — | — | (8,102 | ) | 17,563 | |||||||||||
Transmission/Other | 56,209 | 49,402 | — | — | (14,827 | ) | 90,784 | |||||||||||
Revenue from contracts with customers | 709,024 | 1,024,352 | 52,396 | 65,803 | (103,033 | ) | 1,748,542 | |||||||||||
Other revenues | 2,427 | 955 | 36,556 | 2,230 | (36,442 | ) | 5,726 | |||||||||||
Total revenues | $ | 711,451 | $ | 1,025,307 | $ | 88,952 | $ | 68,033 | $ | (139,475 | ) | $ | 1,754,268 | |||||
Timing of revenue recognition: | ||||||||||||||||||
Services transferred at a point in time | $ | — | $ | — | $ | — | $ | 65,803 | $ | (32,194 | ) | $ | 33,609 | |||||
Services transferred over time | 709,024 | 1,024,352 | 52,396 | — | (70,839 | ) | 1,714,933 | |||||||||||
Revenue from contracts with customers | $ | 709,024 | $ | 1,024,352 | $ | 52,396 | $ | 65,803 | $ | (103,033 | ) | $ | 1,748,542 |
2018 | 2017 | |||||
Materials and supplies | $ | 75,081 | $ | 69,732 | ||
Fuel - Electric Utilities | 2,850 | 2,962 | ||||
Natural gas in storage | 39,368 | 40,589 | ||||
Total materials, supplies and fuel | $ | 117,299 | $ | 113,283 |
2018 | 2017 | |||||
Cost method investment | $ | 28,201 | $ | — | ||
Cash surrender value of life insurance contracts | 12,812 | 13,090 | ||||
Total investments | $ | 41,013 | $ | 13,090 |
2018 | 2017 | |||||
Accrued employee compensation, benefits and withholdings | $ | 63,742 | $ | 52,467 | ||
Accrued property taxes | 42,510 | 42,029 | ||||
Customer deposits and prepayments | 43,574 | 44,420 | ||||
Accrued interest | 31,759 | 33,822 | ||||
CIAC current portion | 1,485 | 1,552 | ||||
Other (none of which is individually significant) | 32,431 | 45,172 | ||||
Total accrued liabilities | $ | 215,501 | $ | 219,462 |
Electric Utilities | Gas Utilities | Power Generation | Total | |||||||||
Ending balance at December 31, 2016 | $ | 248,479 | $ | 1,042,210 | $ | 8,765 | $ | 1,299,454 | ||||
Additions | — | — | — | — | ||||||||
Ending balance at December 31, 2017 | $ | 248,479 | $ | 1,042,210 | $ | 8,765 | $ | 1,299,454 | ||||
Additions | — | — | — | — | ||||||||
Ending balance at December 31, 2018 | $ | 248,479 | $ | 1,042,210 | $ | 8,765 | $ | 1,299,454 |
2018 | 2017 | 2016 | |||||||
Intangible assets, net, beginning balance | $ | 7,559 | $ | 8,392 | $ | 3,380 | |||
Additions (a) | 7,602 | — | 5,522 | ||||||
Amortization expense (b) | (824 | ) | (833 | ) | (510 | ) | |||
Intangible assets, net, ending balance | $ | 14,337 | $ | 7,559 | $ | 8,392 |
(a) | The 2018 addition is related to the Busch Ranch 1 Wind Farm contract intangible asset. See Note 4 for further information. |
(b) | Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years. |
2018 | 2017 | |||||
Regulatory assets | ||||||
Deferred energy and fuel cost adjustments - current (a) | $ | 29,661 | $ | 20,187 | ||
Deferred gas cost adjustments (a) | 3,362 | 31,844 | ||||
Gas price derivatives (a) | 6,201 | 11,935 | ||||
Deferred taxes on AFUDC (b) | 7,841 | 7,847 | ||||
Employee benefit plans (c) | 110,524 | 109,235 | ||||
Environmental (a) | 959 | 1,031 | ||||
Asset retirement obligations (a) | 529 | 517 | ||||
Loss on reacquired debt (a) | 21,001 | 20,667 | ||||
Renewable energy standard adjustment (a) | 1,722 | 1,088 | ||||
Deferred taxes on flow through accounting (c) | 31,044 | 26,978 | ||||
Decommissioning costs | 11,700 | 13,287 | ||||
Gas supply contract termination (a) | 14,310 | 20,001 | ||||
Other regulatory assets (a) | 45,381 | 32,837 | ||||
Total regulatory assets | 284,235 | 297,454 | ||||
Less current regulatory assets | (48,776 | ) | (81,016 | ) | ||
Regulatory assets, non-current | $ | 235,459 | $ | 216,438 | ||
Regulatory liabilities | ||||||
Deferred energy and gas costs (a) | $ | 6,991 | $ | 3,427 | ||
Employee benefit plan costs and related deferred taxes (c) | 42,533 | 40,629 | ||||
Cost of removal (a) | 150,123 | 130,932 | ||||
Excess deferred income taxes (c) | 310,562 | 301,553 | ||||
TCJA revenue reserve | 18,032 | — | ||||
Other regulatory liabilities (c) | 12,553 | 8,585 | ||||
Total regulatory liabilities | 540,794 | 485,126 | ||||
Less current regulatory liabilities | (29,810 | ) | (6,832 | ) | ||
Regulatory liabilities, non-current | $ | 510,984 | $ | 478,294 |
(a) | Recovery of costs, but we are not allowed a rate of return. |
(b) | In addition to recovery of costs, we are allowed a rate of return. |
(c) | In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. |
2018 | 2017 | 2016 | |||||||
Net income (loss) available for common stock | $ | 258,442 | $ | 177,034 | $ | 72,970 | |||
Weighted average shares - basic | 54,420 | 53,221 | 51,922 | ||||||
Dilutive effect of: | |||||||||
Equity Units | 898 | 1,783 | 1,222 | ||||||
Equity compensation | 168 | 116 | 127 | ||||||
Weighted average shares - diluted | 55,486 | 55,120 | 53,271 | ||||||
Net income (loss) available for common stock, per share - Diluted | $ | 4.66 | $ | 3.21 | $ | 1.37 |
2018 | 2017 | 2016 | ||||
Equity compensation | 16 | 11 | 3 | |||
Anti-dilutive shares excluded from computation of earnings (loss) per share | 16 | 11 | 3 |
(in thousands) | |||||
Purchase Price | $ | 1,894,882 | |||
Less: Long-term debt assumed | (760,000 | ) | |||
Less: Working capital adjustment received | (10,644 | ) | |||
Consideration paid, net of working capital adjustment received | $ | 1,124,238 | |||
Allocation of Purchase Price: | |||||
Current Assets | $ | 112,983 | |||
Property, plant & equipment, net | 1,058,093 | ||||
Goodwill | 939,695 | ||||
Deferred charges and other assets, excluding goodwill | 133,299 | ||||
Current liabilities | (172,454 | ) | |||
Long-term debt | (758,874 | ) | |||
Deferred credits and other liabilities | (188,504 | ) | |||
Total consideration paid, net of working-capital adjustment received | $ | 1,124,238 |
Pro Forma Results | |||
December 31, 2016 | |||
(in thousands, except per share amounts) | |||
Revenue | $ | 1,617,878 | |
Income from continuing operations | $ | 177,040 | |
Net income (loss) | $ | 112,878 | |
Earnings from continuing operations per share, Basic | $ | 3.41 | |
Earnings from continuing operations per share, Diluted | $ | 3.32 |
2018 | 2017 | Lives (in years) | ||||||||
Electric Utilities | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Minimum | Maximum | ||||
Electric plant: | ||||||||||
Production | $ | 1,318,643 | 41 | $ | 1,315,044 | 39 | 32 | 46 | ||
Electric transmission | 437,082 | 51 | 407,203 | 51 | 48 | 53 | ||||
Electric distribution | 793,725 | 48 | 755,213 | 48 | 45 | 50 | ||||
Plant acquisition adjustment (a) | 4,870 | 32 | 4,870 | 32 | 32 | 32 | ||||
General | 233,531 | 28 | 232,842 | 31 | 26 | 28 | ||||
Capital lease - plant in service (b) | 261,441 | 20 | 261,441 | 20 | 20 | 20 | ||||
Total electric plant in service | 3,049,292 | 2,976,613 | ||||||||
Construction work in progress | 60,480 | 13,595 | ||||||||
Total electric plant | 3,109,772 | 2,990,208 | ||||||||
Less accumulated depreciation and amortization | 706,869 | 644,022 | ||||||||
Electric plant net of accumulated depreciation and amortization | $ | 2,402,903 | $ | 2,346,186 |
(a) | The plant acquisition adjustment is included in rate base and is being recovered with 12 years remaining. |
(b) | Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031. |
2018 | 2017 | Lives (in years) | ||||||||
Gas Utilities | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Minimum | Maximum | ||||
Gas plant: | ||||||||||
Production | $ | 13,580 | 35 | $ | 10,495 | 35 | 24 | 71 | ||
Gas transmission | 423,873 | 48 | 366,433 | 48 | 22 | 66 | ||||
Gas distribution | 1,595,644 | 42 | 1,413,431 | 42 | 33 | 47 | ||||
Cushion gas - depreciable (a) | 3,539 | 28 | 3,539 | 28 | 28 | 28 | ||||
Cushion gas - not depreciated (a) | 46,369 | N/A | 47,466 | N/A | N/A | N/A | ||||
Storage | 29,335 | 30 | 28,520 | 31 | 28 | 38 | ||||
General | 355,920 | 19 | 336,869 | 19 | 10 | 24 | ||||
Total gas plant in service | 2,468,260 | 2,206,753 | ||||||||
Construction work in progress | 38,271 | 44,440 | ||||||||
Total gas plant | 2,506,531 | 2,251,193 | ||||||||
Less accumulated depreciation and amortization | 279,580 | 229,170 | ||||||||
Gas plant net of accumulated depreciation and amortization | $ | 2,226,951 | $ | 2,022,023 |
(a) | Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides. |
2018 | Lives (in years) | |||||||||||||||||
Property, Plant and Equipment | Construction Work in Progress | Total Property Plant and Equipment | Less Accumulated Depreciation, Depletion and Amortization | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | |||||||||||
Power Generation | $ | 173,997 | $ | 11,796 | $ | 185,793 | $ | 64,273 | $ | 121,520 | 31 | 2 | 40 | |||||
Mining | $ | 175,650 | $ | — | $ | 175,650 | $ | 111,689 | $ | 63,961 | 13 | 2 | 59 |
2017 | Lives (in years) | |||||||||||||||||
Property, Plant and Equipment | Construction Work in Progress | Total Property Plant and Equipment | Less Accumulated Depreciation, Depletion and Amortization | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | |||||||||||
Power Generation | $ | 155,569 | $ | 224 | $ | 155,793 | $ | 57,813 | $ | 97,980 | 33 | 2 | 40 | |||||
Mining | $ | 158,370 | $ | — | $ | 158,370 | $ | 108,844 | $ | 49,526 | 14 | 2 | 59 |
2018 | Lives (in years) | ||||||||||||||||||||
Property, Plant and Equipment | Construction Work in Progress | Total Property Plant and Equipment | Less Accumulated Depreciation, Depletion and Amortization | Add Accumulated Depreciation - Capital Lease Elimination (a) | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | |||||||||||||
Corporate | $ | 5,721 | $ | 16,548 | $ | 22,269 | $ | 670 | $ | 17,945 | $ | 39,544 | 8 | 3 | 30 |
(a) | Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $18 million. |
2017 | Lives (in years) | ||||||||||||||||||||
Property, Plant and Equipment | Construction Work in Progress | Total Property Plant and Equipment | Less Accumulated Depreciation, Depletion and Amortization | Add Accumulated Depreciation - Capital Lease Elimination (a) | Net Property, Plant and Equipment | Weighted Average Useful Life | Minimum | Maximum | |||||||||||||
Corporate | $ | 5,580 | $ | 6,374 | $ | 11,954 | $ | 309 | $ | 14,070 | $ | 25,715 | 8 | 3 | 30 |
(a) | Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million. |
• | South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves. |
• | South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the SPP region. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie. |
• | South Dakota Electric owns 52% of the Wygen III coal-fired generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies coal to Wygen III for the life of the plant. |
• | Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations. |
Plant in Service | Construction Work in Progress | Accumulated Depreciation | |||||||
Wyodak Plant | $ | 115,198 | $ | 384 | $ | 61,730 | |||
Transmission Tie | $ | 20,855 | $ | 1,860 | $ | 6,667 | |||
Wygen I | $ | 119,273 | $ | 498 | $ | 44,155 | |||
Wygen III | $ | 140,072 | $ | 645 | $ | 22,647 |
Total Assets (net of intercompany eliminations) as of December 31, | 2018 | 2017 | ||||
Electric (a) | $ | 2,895,577 | $ | 2,906,275 | ||
Gas | 3,623,475 | 3,426,466 | ||||
Power Generation (a) | 154,203 | 60,852 | ||||
Mining | 80,594 | 65,455 | ||||
Corporate and Other | 209,478 | 115,612 | ||||
Discontinued operations (b) | — | 84,242 | ||||
Total assets | $ | 6,963,327 | $ | 6,658,902 |
(a) | The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. |
(b) | On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information. |
Capital Expenditures (a) for the years ended December 31, | 2018 | 2017 | ||||
Capital expenditures | ||||||
Electric Utilities | $ | 152,524 | $ | 138,060 | ||
Gas Utilities | 288,438 | 184,389 | ||||
Power Generation | 30,945 | 1,864 | ||||
Mining | 18,794 | 6,708 | ||||
Corporate and Other | 11,723 | 6,668 | ||||
Total capital expenditures of continuing operations | 502,424 | 337,689 | ||||
Total capital expenditures of discontinued operations | 2,402 | 23,222 | ||||
Total capital expenditures | $ | 504,826 | $ | 360,911 |
(a) | Includes accruals for property, plant and equipment. |
Property, Plant and Equipment as of December 31, | 2018 | 2017 | ||||
Electric Utilities (a) | $ | 3,109,772 | $ | 2,990,208 | ||
Gas Utilities | 2,506,531 | 2,251,193 | ||||
Power Generation (a) | 185,793 | 155,793 | ||||
Mining | 175,650 | 158,370 | ||||
Corporate and Other | 22,269 | 11,954 | ||||
Total property, plant and equipment | $ | 6,000,015 | $ | 5,567,518 |
(a) | The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. |
Consolidating Income Statement | ||||||||||||||||||||||||
Year ended December 31, 2018 | Electric Utilities | Gas Utilities | Power Generation | Mining | Corporate | Intercompany Eliminations | Discontinued Operations | Total | ||||||||||||||||
Revenue - | ||||||||||||||||||||||||
Contracts with customers | $ | 686,272 | $ | 1,022,828 | $ | 5,833 | $ | 33,609 | $ | — | $ | — | $ | — | $ | 1,748,542 | ||||||||
Other revenues | 2,427 | 955 | 1,413 | 931 | — | — | — | 5,726 | ||||||||||||||||
688,699 | 1,023,783 | 7,246 | 34,540 | — | — | — | 1,754,268 | |||||||||||||||||
Inter-company operating revenue - | ||||||||||||||||||||||||
Contracts with customers | 22,752 | 1,524 | 46,563 | 32,194 | 148 | (103,181 | ) | — | — | |||||||||||||||
Other revenues | — | — | 35,143 | 1,299 | 379,775 | (416,217 | ) | — | — | |||||||||||||||
22,752 | 1,524 | 81,706 | 33,493 | 379,923 | (519,398 | ) | — | — | ||||||||||||||||
Total revenue | 711,451 | 1,025,307 | 88,952 | 68,033 | 379,923 | (519,398 | ) | — | 1,754,268 | |||||||||||||||
Fuel, purchased power and cost of natural gas sold | 277,093 | 462,153 | — | — | 43 | (113,679 | ) | — | 625,610 | |||||||||||||||
Operations and maintenance | 186,175 | 291,481 | 33,727 | 43,728 | 324,917 | (344,735 | ) | — | 535,293 | |||||||||||||||
Depreciation, depletion and amortization | 98,639 | 86,434 | 6,913 | 7,965 | 21,161 | (24,784 | ) | — | 196,328 | |||||||||||||||
Operating income (loss) | 149,544 | 185,239 | 48,312 | 16,340 | 33,802 | (36,200 | ) | — | 397,037 | |||||||||||||||
Interest expense | (55,660 | ) | (85,760 | ) | (5,178 | ) | (538 | ) | (150,455 | ) | 155,975 | — | (141,616 | ) | ||||||||||
Interest income | 2,993 | 5,580 | 183 | 2 | 113,188 | (120,305 | ) | — | 1,641 | |||||||||||||||
Other income (expense), net | (1,235 | ) | (431 | ) | (53 | ) | 164 | 456,481 | (456,106 | ) | — | (1,180 | ) | |||||||||||
Income tax benefit (expense) (a) | (16,702 | ) | 55,655 | (8,267 | ) | (3,069 | ) | (3,804 | ) | (146 | ) | — | 23,667 | |||||||||||
Income (loss) from continuing operations | 78,940 | 160,283 | 34,997 | 12,899 | 449,212 | (456,782 | ) | — | 279,549 | |||||||||||||||
(Loss) from discontinued operations, net of tax | — | — | — | — | — | — | (6,887 | ) | (6,887 | ) | ||||||||||||||
Net income (loss) | 78,940 | 160,283 | 34,997 | 12,899 | 449,212 | (456,782 | ) | (6,887 | ) | 272,662 | ||||||||||||||
Net income attributable to noncontrolling interest | — | — | (14,220 | ) | — | — | — | — | (14,220 | ) | ||||||||||||||
Net income (loss) available for common stock | $ | 78,940 | $ | 160,283 | $ | 20,777 | $ | 12,899 | $ | 449,212 | $ | (456,782 | ) | $ | (6,887 | ) | $ | 258,442 |
(a) | Income tax benefit (expense) includes a tax benefit of $73 million at our Gas Utilities resulting from legal entity restructuring. See Note 15. |
Consolidating Income Statement | ||||||||||||||||||||||||
Year ended December 31, 2017 | Electric Utilities | Gas Utilities | Power Generation | Mining | Corporate | Intercompany Eliminations | Discontinued Operations | Total | ||||||||||||||||
Revenue | $ | 689,945 | $ | 947,595 | $ | 7,263 | $ | 35,463 | $ | — | $ | — | $ | — | $ | 1,680,266 | ||||||||
Intercompany revenue | 14,705 | 35 | 84,283 | 31,158 | 344,685 | (474,866 | ) | — | — | |||||||||||||||
Total revenue | 704,650 | 947,630 | 91,546 | 66,621 | 344,685 | (474,866 | ) | — | 1,680,266 | |||||||||||||||
Fuel, purchased power and cost of natural gas sold | 268,405 | 409,603 | — | — | 151 | (114,871 | ) | — | 563,288 | |||||||||||||||
Operations and maintenance | 172,307 | 269,190 | 32,382 | 44,882 | 296,067 | (302,832 | ) | — | 511,996 | |||||||||||||||
Depreciation, depletion and amortization | 93,315 | 83,732 | 5,993 | 8,239 | 21,031 | (24,064 | ) | — | 188,246 | |||||||||||||||
Operating income (loss) | 170,623 | 185,105 | 53,171 | 13,500 | 27,436 | (33,099 | ) | — | 416,736 | |||||||||||||||
Interest expense | (55,229 | ) | (80,829 | ) | (3,959 | ) | (228 | ) | (152,416 | ) | 154,543 | — | (138,118 | ) | ||||||||||
Interest income | 2,955 | 2,254 | 1,123 | 23 | 115,382 | (120,721 | ) | — | 1,016 | |||||||||||||||
Other income (expense), net | 1,730 | (829 | ) | (54 | ) | 2,191 | 330,373 | (331,303 | ) | — | 2,108 | |||||||||||||
Income tax benefit (expense) | (9,997 | ) | (39,799 | ) | 10,333 | (1,100 | ) | (32,433 | ) | (371 | ) | — | (73,367 | ) | ||||||||||
Income (loss) from continuing operations | 110,082 | 65,902 | 60,614 | 14,386 | 288,342 | (330,951 | ) | — | 208,375 | |||||||||||||||
(Loss) from discontinued operations, net of tax (a) | — | — | — | — | — | — | (17,099 | ) | (17,099 | ) | ||||||||||||||
Net income (loss) | 110,082 | 65,902 | 60,614 | 14,386 | 288,342 | (330,951 | ) | (17,099 | ) | 191,276 | ||||||||||||||
Net income attributable to noncontrolling interest | — | (107 | ) | (14,135 | ) | — | — | — | — | (14,242 | ) | |||||||||||||
Net income (loss) available for common stock | $ | 110,082 | $ | 65,795 | $ | 46,479 | $ | 14,386 | $ | 288,342 | $ | (330,951 | ) | $ | (17,099 | ) | $ | 177,034 |
(a) | Discontinued operations includes oil and gas property impairments. See Note 21. |
Consolidating Income Statement | ||||||||||||||||||||||||
Year ended December 31, 2016 | Electric Utilities | Gas Utilities | Power Generation | Mining | Corporate | Intercompany Eliminations | Discontinued Operations | Total | ||||||||||||||||
Revenue | $ | 664,330 | $ | 838,343 | $ | 7,176 | $ | 29,067 | $ | — | $ | — | $ | — | $ | 1,538,916 | ||||||||
Intercompany revenue | 12,951 | — | 83,955 | 31,213 | 347,500 | (475,619 | ) | — | — | |||||||||||||||
Total revenue | 677,281 | 838,343 | 91,131 | 60,280 | 347,500 | (475,619 | ) | — | 1,538,916 | |||||||||||||||
Fuel, purchased power and cost of natural gas sold | 261,349 | 352,165 | — | — | 456 | (114,838 | ) | — | 499,132 | |||||||||||||||
Operations and maintenance | 158,134 | 245,826 | 32,636 | 39,576 | 378,744 | (326,846 | ) | — | 528,070 | |||||||||||||||
Depreciation, depletion and amortization | 84,645 | 78,335 | 4,104 | 9,346 | 22,930 | (23,827 | ) | — | 175,533 | |||||||||||||||
Operating income (loss) | 173,153 | 162,017 | 54,391 | 11,358 | (54,630 | ) | (10,108 | ) | — | 336,181 | ||||||||||||||
Interest expense | (56,237 | ) | (76,586 | ) | (3,758 | ) | (401 | ) | (114,597 | ) | 115,469 | — | (136,110 | ) | ||||||||||
Interest income | 5,946 | 1,573 | 1,983 | 24 | 97,147 | (105,244 | ) | — | 1,429 | |||||||||||||||
Other income (expense), net | 3,193 | 184 | 2 | 2,209 | 179,838 | (181,032 | ) | — | 4,394 | |||||||||||||||
Income tax benefit (expense) | (40,228 | ) | (27,462 | ) | (17,129 | ) | (3,137 | ) | 28,398 | 457 | — | (59,101 | ) | |||||||||||
Income (loss) from continuing operations | 85,827 | 59,726 | 35,489 | 10,053 | 136,156 | (180,458 | ) | — | 146,793 | |||||||||||||||
(Loss) from discontinued operations, net of tax (a) | — | — | — | — | — | — | (64,162 | ) | (64,162 | ) | ||||||||||||||
Net income (loss) | 85,827 | 59,726 | 35,489 | 10,053 | 136,156 | (180,458 | ) | (64,162 | ) | 82,631 | ||||||||||||||
Net income attributable to noncontrolling interest | — | (102 | ) | (9,559 | ) | — | — | — | — | (9,661 | ) | |||||||||||||
Net income (loss) available for common stock | $ | 85,827 | $ | 59,624 | $ | 25,930 | $ | 10,053 | $ | 136,156 | $ | (180,458 | ) | $ | (64,162 | ) | $ | 72,970 |
(a) | Discontinued operations includes oil and gas property impairments. See Note 21. |
Year Ended | ||||||
Business Segment | December 31, 2017 | December 31, 2016 | ||||
Electric Utilities | $ | 1,323 | $ | 2,079 | ||
Gas Utilities | 1,571 | 2,292 | ||||
Power Generation | 177 | 320 | ||||
Mining | 101 | 196 | ||||
Total reportable segments | 3,172 | 4,887 | ||||
Corporate and Other (a) | 6,405 | 6,037 | ||||
Total | $ | 9,577 | $ | 10,924 |
(a) | Includes interest allocations in 2017 and 2016 of approximately $4.9 million and $5.6 million, respectively. |
Interest Rate at | Balance Outstanding | |||||||
Due Date | December 31, 2018 | December 31, 2018 | December 31, 2017 | |||||
Corporate | ||||||||
Senior unsecured notes due 2023 | November 30, 2023 | 4.25% | $ | 525,000 | $ | 525,000 | ||
Senior unsecured notes due 2020 | July 15, 2020 | 5.88% | 200,000 | 200,000 | ||||
Remarketable junior subordinated notes (b) | November 1, 2028 | 3.50% | — | 299,000 | ||||
Senior unsecured notes due 2019 | January 11, 2019 | 2.50% | — | 250,000 | ||||
Senior unsecured notes due 2026 | January 15, 2026 | 3.95% | 300,000 | 300,000 | ||||
Senior unsecured notes due 2027 | January 15, 2027 | 3.15% | 400,000 | 400,000 | ||||
Senior unsecured notes due 2033 | May 1, 2033 | 4.35% | 400,000 | — | ||||
Senior unsecured notes, due 2046 | September 15, 2046 | 4.20% | 300,000 | 300,000 | ||||
Corporate term loan due 2019 | August 9, 2019 | 2.55% | — | 300,000 | ||||
Corporate term loan due 2020 (a) | July 30, 2020 | 3.16% | 300,000 | — | ||||
Corporate term loan due 2021 | June 7, 2021 | 2.32% | 12,921 | 18,664 | ||||
Total Corporate debt | 2,437,921 | 2,592,664 | ||||||
Less unamortized debt discount | (5,122 | ) | (3,808 | ) | ||||
Total Corporate debt, net | 2,432,799 | 2,588,856 | ||||||
Electric Utilities | ||||||||
First Mortgage Bonds due 2044 | October 20, 2044 | 4.43% | 85,000 | 85,000 | ||||
First Mortgage Bonds due 2044 | October 20, 2044 | 4.53% | 75,000 | 75,000 | ||||
First Mortgage Bonds due 2032 | August 15, 2032 | 7.23% | 75,000 | 75,000 | ||||
First Mortgage Bonds due 2039 | November 1, 2039 | 6.13% | 180,000 | 180,000 | ||||
First Mortgage Bonds due 2037 | November 20, 2037 | 6.67% | 110,000 | 110,000 | ||||
Industrial development revenue bonds due 2021 (c) | September 1, 2021 | 1.73% | 7,000 | 7,000 | ||||
Industrial development revenue bonds due 2027 (c) | March 1, 2027 | 1.73% | 10,000 | 10,000 | ||||
Series 94A Debt, variable rate (c) | June 1, 2024 | 1.93% | 2,855 | 2,855 | ||||
Total Electric Utilities debt | 544,855 | 544,855 | ||||||
Less unamortized debt discount | (86 | ) | (90 | ) | ||||
Total Electric Utilities debt, net | 544,769 | 544,765 | ||||||
Total long-term debt | 2,977,568 | 3,133,621 | ||||||
Less current maturities | 5,743 | 5,743 | ||||||
Less unamortized deferred financing costs (d) | 20,990 | 18,478 | ||||||
Long-term debt, net of current maturities and deferred financing costs | $ | 2,950,835 | $ | 3,109,400 |
(a) | Variable interest rate, based on LIBOR plus a spread. |
(b) | See Note 12 for RSN details. |
(c) | Variable interest rate. |
(d) | Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2018 and December 31, 2017, respectively. |
2019 | $ | 5,743 | |
2020 | $ | 505,743 | |
2021 | $ | 8,435 | |
2022 | $ | — | |
2023 | $ | 525,000 | |
Thereafter | $ | 1,937,855 |
Deferred Financing Costs Remaining at | Amortization Expense for the years ended December 31, | |||||||||||
December 31, 2018 | 2018 | 2017 | 2016 | |||||||||
$ | 20,990 | $ | 2,829 | $ | 3,349 | $ | 3,861 |
• | Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2018, the restricted net assets at our Electric and Gas Utilities were approximately $257 million. |
Balance Outstanding at | ||||||
December 31, 2018 | December 31, 2017 | |||||
CP Program | $ | 185,620 | $ | 211,300 |
At December 31, 2018 | Covenant Requirement at December 31, 2018 | |||||
Consolidated Indebtedness to Capitalization Ratio | 59 | % | Less than | 65 | % |
December 31, 2017 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates (b) | December 31, 2018 | |||||||||||||
Electric Utilities | $ | 6,287 | $ | — | $ | — | $ | 269 | $ | 2 | $ | 6,558 | ||||||
Gas Utilities | 33,238 | 152 | — | 1,237 | — | 34,627 | ||||||||||||
Mining | 12,499 | — | (4 | ) | 649 | 2,471 | 15,615 | |||||||||||
Total | $ | 52,024 | $ | 152 | $ | (4 | ) | $ | 2,155 | $ | 2,473 | $ | 56,800 |
December 31, 2016 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates (a) | December 31, 2017 | |||||||||||||
Electric Utilities | $ | 4,661 | $ | — | $ | (4 | ) | $ | 268 | $ | 1,362 | $ | 6,287 | |||||
Gas Utilities | 29,775 | — | — | 1,142 | 2,321 | 33,238 | ||||||||||||
Mining | 12,440 | — | (107 | ) | 651 | (485 | ) | 12,499 | ||||||||||
Total | $ | 46,876 | $ | — | $ | (111 | ) | $ | 2,061 | $ | 3,198 | $ | 52,024 |
(a) | The Gas Utilities’ Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. |
(b) | The increase in the Mining Revision to Prior Estimates was primarily driven by higher costs associated with back-filling the pit with overburden removed during the mining process. |
• | Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, market speculation, pipeline constraints, and other factors that may impact natural gas supply and demand; |
• | Interest rate risk associated with our variable debt. |
December 31, 2018 | December 31, 2017 | |||||
Notional (MMBtus) | Maximum Term (months) (a) | Notional (MMBtus) | Maximum Term (months) (a) | |||
Natural gas futures purchased | 4,000,000 | 24 | 8,330,000 | 36 | ||
Natural gas options purchased, net | 4,320,000 | 13 | 3,540,000 | 14 | ||
Natural gas basis swaps purchased | 3,960,000 | 24 | 8,060,000 | 36 | ||
Natural gas over-the-counter swaps, net (b) | 3,660,000 | 24 | 3,820,000 | 29 | ||
Natural gas physical commitments, net (c) | 18,325,852 | 30 | 12,826,605 | 35 |
(a) | Term reflects the maximum forward period hedged. |
(b) | As of December 31, 2018, 1,542,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. |
(c) | Volumes exclude contracts that qualify for normal purchase, normal sales exception. |
December 31, 2018 | ||||||||
Derivatives in Cash Flow Hedging Relationships | Location of Reclassifications from AOCI into Income | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | ||||
Interest rate swaps | Interest expense | $ | (2,851 | ) | Interest expense | $ | — | |
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (130 | ) | Fuel, purchased power and cost of natural gas sold | — | |||
Total impact from cash flow hedges | $ | (2,981 | ) | $ | — |
December 31, 2017 | ||||||||
Derivatives in Cash Flow Hedging Relationships | Location of Reclassifications from AOCI into Income | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | ||||
Interest rate swaps | Interest expense | $ | (2,941 | ) | Interest expense | $ | — | |
Commodity derivatives | Net (loss) from discontinued operations | 913 | Net (loss) from discontinued operations | — | ||||
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (243 | ) | Fuel, purchased power and cost of natural gas sold | (75 | ) | ||
Total | $ | (2,271 | ) | $ | (75 | ) |
December 31, 2016 | ||||||||
Derivatives in Cash Flow Hedging Relationships | Location of Reclassifications from AOCI into Income | Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) | Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) | ||||
Interest rate swaps | Interest expense | $ | (3,899 | ) | Interest expense | $ | (953 | ) |
Commodity derivatives | Net (loss) from discontinued operations | 11,019 | Net (loss) from discontinued operations | — | ||||
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (14 | ) | Fuel, purchased power and cost of natural gas sold | — | |||
Total | $ | 7,106 | $ | (953 | ) |
December 31, 2018 | December 31, 2017 | December 31, 2016 | |||||||
(In thousands) | |||||||||
Increase (decrease) in fair value: | |||||||||
Interest rate swaps | $ | — | $ | — | $ | (31,222 | ) | ||
Forward commodity contracts | 983 | 366 | (573 | ) | |||||
Recognition of (gains) losses in earnings due to settlements: | |||||||||
Interest rate swaps | 2,851 | 2,941 | 3,899 | ||||||
Forward commodity contracts | 130 | (670 | ) | (11,005 | ) | ||||
Total other comprehensive income (loss) from hedging | $ | 3,964 | $ | 2,637 | $ | (38,901 | ) |
December 31, 2018 | December 31, 2017 | December 31, 2016 | ||||||||
Derivatives Not Designated as Hedging Instruments | Location of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | Amount of Gain/(Loss) on Derivatives Recognized in Income | ||||||
Commodity derivatives | Net (loss) from discontinued operations | $ | — | $ | — | $ | (50 | ) | ||
Commodity derivatives | Fuel, purchased power and cost of natural gas sold | 1,101 | (2,207 | ) | 940 | |||||
$ | 1,101 | $ | (2,207 | ) | $ | 890 |
As of December 31, 2018 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Cash Collateral and Counterparty Netting | Total | ||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives - Utilities | $ | — | $ | 2,927 | $ | — | $ | (1,408 | ) | $ | 1,519 | |||||
Total | $ | — | $ | 2,927 | $ | — | $ | (1,408 | ) | $ | 1,519 | |||||
Liabilities: | ||||||||||||||||
Commodity derivatives - Utilities | $ | — | $ | 6,801 | $ | — | $ | (5,794 | ) | $ | 1,007 | |||||
Total | $ | — | $ | 6,801 | $ | — | $ | (5,794 | ) | $ | 1,007 |
As of December 31, 2017 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Cash Collateral and Counterparty Netting | Total | ||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives - Utilities | $ | — | 1,586 | $ | — | $ | (1,282 | ) | $ | 304 | ||||||
Total | $ | — | $ | 1,586 | $ | — | $ | (1,282 | ) | $ | 304 | |||||
Liabilities: | ||||||||||||||||
Commodity derivatives - Utilities | $ | — | $ | 13,756 | $ | — | $ | (11,497 | ) | $ | 2,259 | |||||
Total | $ | — | $ | 13,756 | $ | — | $ | (11,497 | ) | $ | 2,259 |
December 31, | |||||||
Balance Sheet Location | 2018 | 2017 | |||||
Derivatives designated as hedges: | |||||||
Asset derivative instruments: | |||||||
Current commodity derivatives | Derivative assets - current | $ | 415 | $ | — | ||
Noncurrent commodity derivatives | Other assets, non-current | 18 | — | ||||
Liability derivative instruments: | |||||||
Current commodity derivatives | Derivative liabilities - current | (114 | ) | (817 | ) | ||
Noncurrent commodity derivatives | Other deferred credits and other liabilities | (4 | ) | (67 | ) | ||
Total derivatives designated as hedges | $ | 315 | $ | (884 | ) | ||
Not designated as hedges: | |||||||
Asset derivative instruments: | |||||||
Current commodity derivatives | Derivative assets - current | $ | 1,085 | $ | 304 | ||
Noncurrent commodity derivatives | Other assets, non-current | 1 | — | ||||
Liability derivative instruments: | |||||||
Current commodity derivatives | Derivative liabilities - current | (833 | ) | (1,264 | ) | ||
Noncurrent commodity derivatives | Other deferred credits and other liabilities | (56 | ) | (111 | ) | ||
Total derivatives not designated as hedges | $ | 197 | $ | (1,071 | ) |
Derivative Assets | Gross Amounts of Derivative Assets | Gross Amounts Offset on Consolidated Balance Sheets | Net Amount of Total Derivative Assets on Consolidated Balance Sheets | ||||||
Commodity derivative assets subject to a master netting agreement or similar arrangement | $ | 1,408 | $ | (1,408 | ) | $ | — | ||
Commodity derivative assets not subject to a master netting agreement or similar arrangement | 1,519 | — | 1,519 | ||||||
Total derivative assets | $ | 2,927 | $ | (1,408 | ) | $ | 1,519 |
Derivative Liabilities | Gross Amounts of Derivative Liabilities | Gross Amounts Offset on Consolidated Balance Sheets | Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets | ||||||
Commodity derivative liabilities subject to a master netting agreement or similar arrangement | $ | 5,794 | $ | (5,794 | ) | $ | — | ||
Commodity derivative liabilities not subject to a master netting agreement or similar arrangement | 1,007 | — | 1,007 | ||||||
Total derivative liabilities | $ | 6,801 | $ | (5,794 | ) | $ | 1,007 |
Derivative Assets | Gross Amounts of Derivative Assets | Gross Amounts Offset on Consolidated Balance Sheets | Net Amount of Total Derivative Assets on Consolidated Balance Sheets | ||||||
Commodity derivative assets subject to a master netting agreement or similar arrangement | $ | 1,282 | $ | (1,282 | ) | $ | — | ||
Commodity derivative assets not subject to a master netting agreement or similar arrangement | 304 | — | 304 | ||||||
Total derivative assets | $ | 1,586 | $ | (1,282 | ) | $ | 304 |
Derivative Liabilities | Gross Amounts of Derivative Liabilities | Gross Amounts Offset on Consolidated Balance Sheets | Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets | ||||||
Commodity derivative liabilities subject to a master netting agreement or similar arrangement | $ | 11,497 | $ | (11,497 | ) | $ | — | ||
Commodity derivative liabilities not subject to a master netting agreement or similar arrangement | 2,259 | — | 2,259 | ||||||
Total derivative liabilities | $ | 13,756 | $ | (11,497 | ) | $ | 2,259 |
2018 | 2017 | |||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||
Cash and cash equivalents (a) | $ | 20,776 | $ | 20,776 | $ | 15,420 | $ | 15,420 | ||||
Restricted cash and equivalents (a) | $ | 3,369 | $ | 3,369 | $ | 2,820 | $ | 2,820 | ||||
Notes payable (b) | $ | 185,620 | $ | 185,620 | $ | 211,300 | $ | 211,300 | ||||
Long-term debt, including current maturities (c) (d) | $ | 2,956,578 | $ | 3,039,108 | $ | 3,115,143 | $ | 3,350,544 |
(a) | Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. |
(b) | Notes payable consist of commercial paper borrowings. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. |
(c) | Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. |
(d) | Carrying amount of long-term debt is net of deferred financing costs. |
2018 | 2017 | 2016 | |||||||
Stock-based compensation expense | $ | 12,390 | $ | 7,626 | $ | 10,885 |
Restricted Stock | Weighted-Average Grant Date Fair Value | ||||
(in thousands) | |||||
Balance at beginning of period | 267 | $ | 55.94 | ||
Granted | 113 | 57.31 | |||
Vested | (119 | ) | 54.24 | ||
Forfeited | (25 | ) | 55.52 | ||
Balance at end of period | 236 | $ | 57.50 |
Weighted-Average Grant Date Fair Value | Total Fair Value of Shares Vested | |||||
(in thousands) | ||||||
2018 | $ | 57.31 | $ | 6,776 | ||
2017 | $ | 60.63 | $ | 7,909 | ||
2016 | $ | 53.55 | $ | 4,602 |
Possible Payout Range of Target | ||||
Grant Date | Performance Period | Target Grant of Shares | Minimum | Maximum |
January 1, 2016 | January 1, 2016 - December 31, 2018 | 51 | 0% | 200% |
January 1, 2017 | January 1, 2017 - December 31, 2019 | 49 | 0% | 200% |
January 1, 2018 | January 1, 2018 - December 31, 2020 | 53 | 0% | 200% |
Equity Portion | Liability Portion | |||||||||
Weighted-Average Grant Date Fair Value (a) | Weighted-Average Fair Value at | |||||||||
Shares | Shares | December 31, 2018 | ||||||||
(in thousands) | (in thousands) | |||||||||
Performance Shares balance at beginning of period | 74 | $ | 55.31 | 74 | ||||||
Granted | 28 | 61.82 | 28 | |||||||
Forfeited | (3 | ) | 58.14 | (3 | ) | |||||
Vested | (22 | ) | 54.92 | (22 | ) | |||||
Performance Shares balance at end of period | 77 | $ | 57.66 | 77 | $ | 76.03 |
(a) | The grant date fair values for the performance shares granted in 2018, 2017 and 2016 were determined by Monte Carlo simulation using a blended volatility of 21%, 23% and 24%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. |
Weighted Average Grant Date Fair Value | |||
December 31, 2018 | $ | 61.82 | |
December 31, 2017 | $ | 63.52 | |
December 31, 2016 | $ | 47.76 |
2018 | 2017 | ||||||
(in thousands) | |||||||
Assets | |||||||
Current assets | $ | 13,620 | $ | 14,837 | |||
Property, plant and equipment of variable interest entities, net | $ | 199,839 | $ | 208,595 | |||
Liabilities | |||||||
Current liabilities | $ | 5,174 | $ | 4,565 |
State | Approximate 2018 Benefit for Customers | Start Date for Customer Benefits | ||
Arkansas | $ | 9.7 | million | October 2018 |
Colorado | $ | 10.8 | million | July 2018 |
Iowa | $ | 2.2 | million | June 2018 |
Kansas | $ | 1.9 | million | April 2018 |
Nebraska | $ | 3.8 | million | July 2018 |
South Dakota | $ | 7.6 | million | October 2018 |
2018 | 2017 | 2016 | |||||||
Rent expense (a) | $ | 2,667 | $ | 10,325 | $ | 9,568 |
(a) | The decrease in rent expense is primarily driven by current year expiration of office leases and by purchases of facilities previously leased. |
2019 | $ | 1,052 | |
2020 | $ | 464 | |
2021 | $ | 344 | |
2022 | $ | 224 | |
2023 | $ | 216 | |
Thereafter | $ | 1,776 |
2018 | 2017 | 2016 | |||||||
Current: | |||||||||
Federal | $ | 325 | $ | (6,193 | ) | $ | (21,806 | ) | |
State | 247 | (1,432 | ) | (1,797 | ) | ||||
572 | (7,625 | ) | (23,603 | ) | |||||
Deferred: | |||||||||
Federal | (23,295 | ) | 76,567 | 78,997 | |||||
State | 815 | 4,470 | 3,759 | ||||||
Excess deferred tax amortization | (1,727 | ) | — | — | |||||
Tax credit amortization | (32 | ) | (45 | ) | (52 | ) | |||
(24,239 | ) | 80,992 | 82,704 | ||||||
$ | (23,667 | ) | $ | 73,367 | $ | 59,101 |
2018 | 2017 | |||||
Deferred tax assets: | ||||||
Regulatory liabilities | $ | 92,966 | $ | 90,742 | ||
Employee benefits | 14,039 | 18,724 | ||||
Federal net operating loss | 139,371 | 155,276 | ||||
Other deferred tax assets(a) | 101,579 | 74,561 | ||||
Less: Valuation allowance | (11,809 | ) | (9,121 | ) | ||
Total deferred tax assets | 336,146 | 330,182 | ||||
Deferred tax liabilities: | ||||||
Accelerated depreciation, amortization and other property-related differences | (529,338 | ) | (510,774 | ) | ||
Regulatory assets | (32,324 | ) | (26,245 | ) | ||
Goodwill (b) | (602 | ) | (46,392 | ) | ||
State deferred tax liability | (64,095 | ) | (58,930 | ) | ||
Deferred costs | (13,351 | ) | (16,063 | ) | ||
Other deferred tax liabilities | (7,767 | ) | (8,298 | ) | ||
Total deferred tax liabilities | (647,477 | ) | (666,702 | ) | ||
Net deferred tax liability | $ | (311,331 | ) | $ | (336,520 | ) |
(a) | Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability. |
(b) | Legal entity restructuring - see above. |
2018 | 2017 | 2016 | ||||
Federal statutory rate | 21.0 | % | 35.0 | % | 35.0 | % |
State income tax (net of federal tax effect) | 2.3 | 0.9 | 1.2 | |||
Percentage depletion | (0.4 | ) | (0.6 | ) | (0.8 | ) |
Non-controlling interest (a) | (1.3 | ) | (1.8 | ) | (1.6 | ) |
Equity AFUDC | — | (0.2 | ) | (0.5 | ) | |
Tax credits | (2.0 | ) | (1.7 | ) | (0.4 | ) |
Transaction costs | — | — | 0.5 | |||
Accounting for uncertain tax positions adjustment | — | (0.2 | ) | (2.7 | ) | |
Flow-through adjustments (b) | (1.6 | ) | (1.1 | ) | (2.1 | ) |
Jurisdictional simplification project (d) | (28.5 | ) | — | — | ||
Other tax differences | (0.4 | ) | (0.9 | ) | 0.1 | |
IRC 172(f) carryback claim | — | (0.7 | ) | — | ||
TCJA corporate rate reduction (c) | 1.6 | (2.7 | ) | — | ||
(9.3 | )% | 26.0 | % | 28.7 | % |
(a) | The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded. |
(b) | Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. |
(c) | On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. During the year ended December 31, 2018, we recorded approximately $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded approximately $8.0 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. |
(d) | Legal entity restructuring - see above. |
Amounts | Expiration Dates | |||||||
Federal Net Operating Loss Carryforward | $ | 663,741 | 2021 | to | 2038 | |||
State Net Operating Loss Carryforward | $ | 542,632 | 2019 | to | 2038 |
Changes in Uncertain Tax Positions | |||
Beginning balance at January 1, 2016 | $ | 31,986 | |
Additions for prior year tax positions | 2,423 | ||
Reductions for prior year tax positions | (19,174 | ) | |
Additions for current year tax positions | — | ||
Settlements | (11,643 | ) | |
Ending balance at December 31, 2016 | 3,592 | ||
Additions for prior year tax positions | 358 | ||
Reductions for prior year tax positions | (5,713 | ) | |
Additions for current year tax positions | 5,026 | ||
Settlements | — | ||
Ending balance at December 31, 2017 | 3,263 | ||
Additions for prior year tax positions | 251 | ||
Reductions for prior year tax positions | (417 | ) | |
Additions for current year tax positions | 486 | ||
Settlements | — | ||
Ending balance at December 31, 2018 | $ | 3,583 |
State Tax Credit Carryforwards | Expiration Year | |||||
Investment tax credit | $ | 20,285 | 2023 | to | 2036 | |
Research and development | $ | 180 | No expiration |
Location on the Consolidated Statements of Income (Loss) | Amount Reclassified from AOCI | ||||||
December 31, 2018 | December 31, 2017 | ||||||
Gains and (losses) on cash flow hedges: | |||||||
Interest rate swaps | Interest expense | $ | (2,851 | ) | $ | (2,941 | ) |
Commodity contracts | Net (loss) from discontinued operations | — | 913 | ||||
Commodity contracts | Fuel, purchased power and cost of natural gas sold | (130 | ) | (243 | ) | ||
(2,981 | ) | (2,271 | ) | ||||
Income tax | Income tax benefit (expense) | 630 | 875 | ||||
Total reclassification adjustments related to cash flow hedges, net of tax | $ | (2,351 | ) | $ | (1,396 | ) | |
Amortization of components of defined benefit plans: | |||||||
Prior service cost | Operations and maintenance | $ | 178 | $ | 168 | ||
Prior service cost | Net (loss) from discontinued operations | — | 29 | ||||
Actuarial gain (loss) | Operations and maintenance | (2,487 | ) | (1,599 | ) | ||
Actuarial gain (loss) | Net (loss) from discontinued operations | — | (58 | ) | |||
(2,309 | ) | (1,460 | ) | ||||
Income tax | Income tax benefit (expense) | 543 | (516 | ) | |||
Total reclassification adjustments related to defined benefit plans, net of tax | (1,766 | ) | (1,976 | ) | |||
Total reclassifications | $ | (4,117 | ) | $ | (3,372 | ) |
Derivatives Designated as Cash Flow Hedges | ||||||||||||
Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total | |||||||||
As of December 31, 2017 | $ | (19,581 | ) | $ | (518 | ) | $ | (21,103 | ) | $ | (41,202 | ) |
Other comprehensive income (loss) | ||||||||||||
before reclassifications | — | 755 | 2,155 | 2,910 | ||||||||
Amounts reclassified from AOCI | 2,252 | 99 | 1,766 | 4,117 | ||||||||
Reclassification to regulatory asset | — | — | 6,519 | 6,519 | ||||||||
Reclassification of certain tax effects from AOCI | 22 | (8 | ) | 726 | 740 | |||||||
As of December 31, 2018 | $ | (17,307 | ) | $ | 328 | $ | (9,937 | ) | $ | (26,916 | ) | |
Derivatives Designated as Cash Flow Hedges | ||||||||||||
Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total | |||||||||
As of December 31, 2016 | $ | (18,109 | ) | $ | (233 | ) | $ | (16,541 | ) | $ | (34,883 | ) |
Other comprehensive income (loss) | ||||||||||||
before reclassifications | — | 231 | (1,890 | ) | (1,659 | ) | ||||||
Amounts reclassified from AOCI | 1,912 | (516 | ) | 944 | 2,340 | |||||||
Reclassification of certain tax effects from AOCI | (3,384 | ) | — | (3,616 | ) | (7,000 | ) | |||||
As of December 31, 2017 | $ | (19,581 | ) | $ | (518 | ) | $ | (21,103 | ) | $ | (41,202 | ) |
Years ended December 31, | 2018 | 2017 | 2016 | ||||||||
(in thousands) | |||||||||||
Non-cash investing activities and financing from continuing operations - | |||||||||||
Property, plant and equipment acquired with accrued liabilities | $ | 69,017 | $ | 28,191 | $ | 27,034 | |||||
Increase (decrease) in capitalized assets associated with asset retirement obligations | $ | 2,625 | $ | 3,198 | $ | 8,577 | |||||
Cash (paid) refunded during the period for continuing operations- | |||||||||||
Interest (net of amount capitalized) | $ | (137,965 | ) | $ | (132,428 | ) | $ | (113,627 | ) | ||
Income taxes (paid) refunded | $ | (14,730 | ) | $ | 1,775 | $ | (1,156 | ) |
2018 | 2017 | |
Equity | 17% | 26% |
Real estate | 4 | 4 |
Fixed income | 71 | 63 |
Cash | 3 | 1 |
Hedge funds | 5 | 6 |
Total | 100% | 100% |
2018 | 2017 | |||||
Defined Contribution Plan | ||||||
Company retirement contribution | $ | 8,766 | $ | 10,223 | ||
Matching contributions | $ | 13,559 | $ | 9,811 |
2018 | 2017 | |||||
Defined Benefit Plans | ||||||
Defined Benefit Pension Plan | $ | 12,700 | $ | 27,700 | ||
Non-Pension Defined Benefit Postretirement Healthcare Plans | $ | 5,298 | $ | 4,332 | ||
Supplemental Non-Qualified Defined Benefit Plans | $ | 2,073 | $ | 3,217 |
Pension Plan | December 31, 2018 | ||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total Investments Measured at Fair Value | NAV (a) | Total Investments | ||||||||||||||||||
AXA Equitable General Fixed Income | $ | — | $ | 1,867 | $ | — | $ | 1,867 | $ | — | $ | 1,867 | |||||||||||
Common Collective Trust - Cash and Cash Equivalents | — | 9,923 | — | 9,923 | — | 9,923 | |||||||||||||||||
Common Collective Trust - Equity | — | 67,457 | — | 67,457 | — | 67,457 | |||||||||||||||||
Common Collective Trust - Fixed Income | — | 279,148 | — | 279,148 | — | 279,148 | |||||||||||||||||
Common Collective Trust - Real Estate | — | 67 | — | 67 | 13,551 | 13,618 | |||||||||||||||||
Hedge Funds | — | — | — | — | 18,783 | 18,783 | |||||||||||||||||
Total investments measured at fair value | $ | — | $ | 358,462 | $ | — | $ | 358,462 | $ | 32,334 | $ | 390,796 |
Pension Plan | December 31, 2017 | ||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total Investments Measured at Fair Value | NAV (a) | Total Investments | ||||||||||||||||||
AXA Equitable General Fixed Income | $ | — | $ | 1,280 | $ | — | $ | 1,280 | $ | — | $ | 1,280 | |||||||||||
Common Collective Trust - Cash and Cash Equivalents | — | 2,184 | — | 2,184 | — | 2,184 | |||||||||||||||||
Common Collective Trust - Equity | — | 109,496 | — | 109,496 | — | 109,496 | |||||||||||||||||
Common Collective Trust - Fixed Income | — | 262,329 | — | 262,329 | — | 262,329 | |||||||||||||||||
Common Collective Trust - Real Estate | — | 1,728 | — | 1,728 | 15,701 | 17,429 | |||||||||||||||||
Hedge Funds | — | — | — | — | 23,625 | 23,625 | |||||||||||||||||
Total investments measured at fair value | $ | — | $ | 377,017 | $ | — | $ | 377,017 | $ | 39,326 | $ | 416,343 |
(a) | Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. |
Non-pension Defined Benefit Postretirement Healthcare Plans | December 31, 2018 | ||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total Investments Measured at Fair Value | NAV (a) | Total Investments | ||||||||||||||||||
Cash and Cash Equivalents | $ | 4,873 | $ | — | $ | — | $ | 4,873 | $ | — | $ | 4,873 | |||||||||||
Equity Securities | 1,005 | — | — | 1,005 | — | 1,005 | |||||||||||||||||
Intermediate-term Bond | — | 2,284 | — | 2,284 | — | 2,284 | |||||||||||||||||
Total investments measured at fair value | $ | 5,878 | $ | 2,284 | $ | — | $ | 8,162 | $ | — | $ | 8,162 |
Non-pension Defined Benefit Postretirement Healthcare Plans | December 31, 2017 | ||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total Investments Measured at Fair Value | NAV (a) | Total Investments | ||||||||||||||||||
Cash and Cash Equivalents | $ | 4,671 | $ | — | $ | — | $ | 4,671 | $ | — | $ | 4,671 | |||||||||||
Equity Securities | 1,374 | — | — | 1,374 | — | 1,374 | |||||||||||||||||
Intermediate-term Bond | — | 2,576 | — | 2,576 | — | 2,576 | |||||||||||||||||
Total investments measured at fair value | $ | 6,045 | $ | 2,576 | $ | — | $ | 8,621 | $ | — | $ | 8,621 |
(a) | Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above. |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans | ||||||||||||||||||
As of December 31 (in thousands), | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | ||||||||||||||
Change in benefit obligation: | ||||||||||||||||||||
Projected benefit obligation at beginning of year | $ | 474,725 | $ | 440,179 | $ | 45,112 | $ | 43,869 | $ | 69,339 | $ | 68,023 | ||||||||
Service cost | 6,834 | 7,034 | 1,764 | 2,937 | 2,291 | 2,300 | ||||||||||||||
Interest cost | 15,470 | 15,520 | 1,170 | 1,276 | 2,085 | 2,141 | ||||||||||||||
Actuarial (gain) loss | (31,340 | ) | 36,661 | (2,963 | ) | 247 | (9,045 | ) | (396 | ) | ||||||||||
Amendments | — | — | — | — | — | 265 | ||||||||||||||
Benefits paid | (20,308 | ) | (24,669 | ) | (2,073 | ) | (3,217 | ) | (5,298 | ) | (4,332 | ) | ||||||||
Plan participants’ contributions | — | — | — | — | 1,445 | 1,338 | ||||||||||||||
Projected benefit obligation at end of year | $ | 445,381 | $ | 474,725 | $ | 43,010 | $ | 45,112 | $ | 60,817 | $ | 69,339 |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans (a) | ||||||||||||||||||
As of December 31 (in thousands), | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | ||||||||||||||
Change in fair value of plan assets: | ||||||||||||||||||||
Beginning fair value of plan assets | $ | 416,343 | $ | 364,695 | $ | — | $ | — | $ | 8,621 | $ | 8,470 | ||||||||
Investment income (loss) | (17,939 | ) | 48,617 | — | — | (149 | ) | 120 | ||||||||||||
Employer contributions | 12,700 | 27,700 | 2,073 | 3,217 | 3,543 | 3,025 | ||||||||||||||
Retiree contributions | — | — | — | — | 1,445 | 1,338 | ||||||||||||||
Benefits paid | (20,308 | ) | (24,669 | ) | (2,073 | ) | (3,217 | ) | (5,298 | ) | (4,332 | ) | ||||||||
Ending fair value of plan assets | $ | 390,796 | $ | 416,343 | $ | — | $ | — | $ | 8,162 | $ | 8,621 |
(a) | Assets of VEBAs and Grantor Trust. |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans | ||||||||||||||||||
2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||
Regulatory assets | $ | 82,919 | $ | 72,756 | $ | — | $ | — | $ | 6,655 | $ | 11,507 | ||||||||
Current liabilities | $ | — | $ | — | $ | 1,463 | $ | 1,372 | $ | 3,885 | $ | 4,423 | ||||||||
Non-current assets | $ | — | $ | — | $ | — | $ | — | $ | 249 | $ | 69 | ||||||||
Non-current liabilities | $ | 54,585 | $ | 58,381 | $ | 41,547 | $ | 43,739 | $ | 49,015 | $ | 56,365 | ||||||||
Regulatory liabilities | $ | 4,620 | $ | 5,232 | $ | — | $ | — | $ | 5,207 | $ | 3,334 |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans | ||||||||||||||||||
As of December 31 (in thousands) | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | ||||||||||||||
Accumulated Benefit Obligation | $ | 428,851 | $ | 450,394 | $ | 40,530 | $ | 41,243 | $ | 60,817 | $ | 69,339 |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans | |||||||||||||||||||||||||||
2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||||||||||||
Service cost | $ | 6,834 | $ | 7,034 | $ | 7,619 | $ | 1,764 | $ | 1,546 | $ | 1,335 | $ | 2,291 | $ | 2,300 | $ | 1,757 | |||||||||||
Interest cost | 15,470 | 15,520 | 15,743 | 1,170 | 1,276 | 1,257 | 2,085 | 2,141 | 1,942 | ||||||||||||||||||||
Expected return on assets | (24,741 | ) | (24,517 | ) | (23,062 | ) | — | — | — | (315 | ) | (315 | ) | (279 | ) | ||||||||||||||
Net amortization of prior service cost | 58 | 58 | 58 | 2 | 2 | 2 | (398 | ) | (411 | ) | (428 | ) | |||||||||||||||||
Recognized net actuarial loss (gain) | 8,632 | 4,007 | 7,173 | 1,000 | 1,001 | 829 | 216 | 499 | 335 | ||||||||||||||||||||
Settlement expense(a) | — | — | 10 | — | — | — | — | — | |||||||||||||||||||||
Net periodic expense | $ | 6,253 | $ | 2,102 | $ | 7,541 | $ | 3,936 | $ | 3,825 | $ | 3,423 | $ | 3,879 | $ | 4,214 | $ | 3,327 |
(a) | Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year. |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans | ||||||||||||||||||
2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||
Net (gain) loss | $ | 11,967 | $ | 10,056 | $ | 4,668 | $ | 6,639 | $ | 860 | $ | 1,309 | ||||||||
Prior service cost (gain) | 1 | 21 | 3 | 4 | (317 | ) | (542 | ) | ||||||||||||
Reclassification of certain tax effects from AOCI | (594 | ) | 2,087 | (87 | ) | 1,371 | (45 | ) | 158 | |||||||||||
Reclassification to regulatory asset | (5,600 | ) | — | — | — | (919 | ) | — | ||||||||||||
Total AOCI | $ | 5,774 | $ | 12,164 | $ | 4,584 | $ | 8,014 | $ | (421 | ) | $ | 925 |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans | ||||||||||||||||||
Weighted-average assumptions used to determine benefit obligations: | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||
Discount rate | 4.40 | % | 3.71 | % | 4.27 | % | 4.34 | % | 3.56 | % | 4.02 | % | 4.28 | % | 3.60 | % | 3.96 | % | ||
Rate of increase in compensation levels | 3.52 | % | 3.43 | % | 3.47 | % | 5.00 | % | 5.00 | % | 5.00 | % | N/A | N/A | N/A |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plans | ||||||||||||||||||
Weighted-average assumptions used to determine net periodic benefit cost for plan year: | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | 2018 | 2017 | 2016 | |||||||||||
Discount rate (a) | 3.71 | % | 4.27 | % | 4.50 | % | 3.67 | % | 4.02 | % | 4.28 | % | 3.60 | % | 4.05 | % | 4.18 | % | ||
Expected long-term rate of return on assets (b) | 6.25 | % | 6.75 | % | 6.87 | % | N/A | N/A | N/A | 3.93 | % | 3.88 | % | 3.83 | % | |||||
Rate of increase in compensation levels | 3.43 | % | 3.47 | % | 3.42 | % | 5.00 | % | 5.00 | % | 5.00 | % | N/A | N/A | N/A |
(a) | The estimated discount rate for the Defined Benefit Pension Plan is 4.40% for the calculation of the 2019 net periodic pension costs. |
(b) | The expected rate of return on plan assets is 6.00% for the calculation of the 2019 net periodic pension cost. |
2018 | 2017 | |
Trend Rate - Medical | ||
Pre-65 for next year - All Plans | 6.70% | 7.00% |
Pre-65 Ultimate trend rate - Black Hills Corp | 4.50% | 4.50% |
Trend Year | 2027 | 2027 |
Post-65 for next year - All Plans | 4.94% | 5.00% |
Post-65 Ultimate trend rate - Black Hills Corp | 4.50% | 4.50% |
Trend Year | 2026 | 2026 |
Defined Benefit Pension Plan | Supplemental Non-qualified Defined Benefit Plans | Non-Pension Defined Benefit Postretirement Healthcare Plans | |||||||||
2019 | $ | 24,405 | $ | 1,463 | $ | 4,898 | |||||
2020 | $ | 25,847 | $ | 1,406 | $ | 5,545 | |||||
2021 | $ | 26,951 | $ | 1,617 | $ | 5,695 | |||||
2022 | $ | 27,972 | $ | 1,727 | $ | 5,849 | |||||
2023 | $ | 29,002 | $ | 1,912 | $ | 5,607 | |||||
2024-2028 | $ | 151,915 | $ | 12,208 | $ | 24,953 |
• | Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit. |
• | South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants. |
• | South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp expiring December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp. |
• | Wyoming Electric’s PPA with Duke Energy’s Happy Jack wind site, expiring September 3, 2028, provides up to 30 MW of wind energy from Happy Jack to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric. |
• | Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energy from Silver Sage to South Dakota Electric. |
• | South Dakota Electric’s PPA with Platte River Power Authority (PRPA) to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029. |
2018 | 2017 | 2016 | |||||||
PPA with PacifiCorp | $ | 13,681 | $ | 13,218 | $ | 12,221 | |||
Transmission services agreement with PacifiCorp | $ | 1,742 | $ | 1,671 | $ | 1,428 | |||
PPA with Happy Jack | $ | 3,884 | $ | 3,846 | $ | 3,836 | |||
PPA with Silver Sage | $ | 5,376 | $ | 4,934 | $ | 4,949 | |||
Busch Ranch I Wind Farm (a) | $ | — | $ | 1,966 | $ | 2,071 | |||
PPA with Platte River Power Authority | $ | 223 | $ | — | $ | — | |||
PPAs with Cargill (b) | $ | — | $ | — | $ | 10,995 |
(a) | On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I Wind Farm from AltaGas. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm. |
(b) | PPAs with Cargill expired on December 31, 2016. |
CIG Rockies | NNG-Ventura | NWPL-Wyoming | Other | |
2019 | 5,803,117 | 3,650,000 | 720,000 | 236 |
2020 | 75,075 | 3,660,000 | 0 | 0 |
2021 | 0 | 3,650,000 | 0 | 0 |
2022 | 0 | 1,810,000 | 0 | 0 |
2023 | 0 | 0 | 0 | 0 |
Thereafter | 0 | 0 | 0 | 0 |
Power Purchase Agreements | Transportation and storage agreements | |||||
2019 | $ | 22,092 | $ | 129,018 | ||
2020 | $ | 6,837 | $ | 127,326 | ||
2021 | $ | 6,203 | $ | 118,707 | ||
2022 | $ | 6,203 | $ | 92,635 | ||
2023 | $ | 6,204 | $ | 73,919 | ||
Thereafter | $ | — | $ | 148,363 |
• | During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023. |
• | South Dakota Electric has an agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023. |
• | During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves. |
• | South Dakota Electric has a PPA with MEAN expiring May 31, 2028. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement. |
• | South Dakota Electric has an agreement through December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals. |
Maximum Exposure at | ||||
Nature of Guarantee | December 31, 2018 | Expiration | ||
Indemnification for subsidiary reclamation/surety bonds (a) | $ | 54,683 | Ongoing | |
Contract performance guarantee (b) | 39,807 | December 2019 | ||
$ | 94,490 |
(a) | We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets. |
(b) | BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of the Busch Ranch II Wind Farm. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations. The guarantee decreases as progress payments are made. |
As of | |||
(in thousands) | December 31, 2017 | ||
Other current assets | $ | 10,360 | |
Deferred income tax assets, noncurrent, net | 16,966 | ||
Property, plant and equipment, net | 56,916 | ||
Other current liabilities | (18,966 | ) | |
Other noncurrent liabilities | (22,808 | ) | |
Net assets | $ | 42,468 |
For the Years Ended | |||||||||
December 31, 2018 | December 31, 2017 | December 31, 2016 | |||||||
Revenue | $ | 5,897 | $ | 25,382 | $ | 34,058 | |||
Operations and maintenance | 11,014 | 22,872 | 27,187 | ||||||
Loss on sale of assets | 3,259 | — | — | ||||||
Depreciation, depletion and amortization | 1,300 | 7,521 | 13,510 | ||||||
Impairment of long-lived assets | — | 20,385 | 106,957 | ||||||
Total operating expenses | 15,573 | 50,778 | 147,654 | ||||||
Operating (loss) | (9,676 | ) | (25,396 | ) | (113,596 | ) | |||
Interest income (expense), net | (19 | ) | 181 | 698 | |||||
Other income (expense), net | 190 | (297 | ) | 110 | |||||
Income tax benefit | 2,618 | 8,413 | 48,626 | ||||||
(Loss) from discontinued operations | $ | (6,887 | ) | $ | (17,099 | ) | $ | (64,162 | ) |
2016 | |||
Acquisition of properties: | |||
Proved | $ | — | |
Unproved | 910 | ||
Exploration costs | 1,102 | ||
Development costs | 4,657 | ||
Asset retirement obligations incurred | — | ||
Total costs incurred | $ | 6,669 |
2016 | |||||||||
Oil | Gas | NGL | |||||||
(in Mbbls of oil and NGL, and MMcf of gas) | |||||||||
Proved developed and undeveloped reserves: | |||||||||
Balance at beginning of year | 3,450 | 73,412 | 1,752 | ||||||
Production (a) | (319 | ) | (9,430 | ) | (133 | ) | |||
Sales | (570 | ) | (1,291 | ) | (17 | ) | |||
Additions - extensions and discoveries | 3 | 52 | — | ||||||
Revisions to previous estimates | (322 | ) | (8,173 | ) | 110 | ||||
Balance at end of year | 2,242 | 54,570 | 1,712 | ||||||
Proved developed reserves at end of year included above | 2,242 | 54,570 | 1,712 | ||||||
Proved undeveloped reserves at the end of year included in above | — | — | — | ||||||
NYMEX prices | $ | 42.75 | $ | 2.48 | $ | — | |||
Well-head reserve prices(c) | $ | 37.35 | $ | 2.25 | $ | 11.92 |
(a) | Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods. |
(b) | A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production. |
(c) | For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable. |
2016 | |||
Unproved oil and gas properties | $ | 18,547 | |
Proved oil and gas properties | 1,043,558 | ||
Gross capitalized costs | 1,062,105 | ||
Accumulated depreciation, depletion and amortization and valuation allowances | (1,000,091 | ) | |
Net capitalized costs | $ | 62,014 |
2016 | |||
Revenue | $ | 34,058 | |
Production costs | 17,231 | ||
Depreciation, depletion and amortization | 12,574 | ||
Impairment of long-lived assets | 106,957 | ||
Total costs | 136,762 | ||
Results of operations from producing activities before tax | (102,704 | ) | |
Income tax benefit (expense) | 37,916 | ||
Results of operations from producing activities (excluding general and administrative costs and interest costs) | $ | (64,788 | ) |
2016 | |||
Leasehold acquisition cost | $ | 963 | |
Exploration cost | 532 | ||
Capitalized interest | 50 | ||
Total | $ | 1,545 |
2016 | |||
Future cash inflows | $ | 246,221 | |
Future production costs | (166,248 | ) | |
Future development costs, including plugging and abandonment | (18,333 | ) | |
Future net cash flows | 61,640 | ||
10% annual discount for estimated timing of cash flows | (26,574 | ) | |
Standardized measure of discounted future net cash flows | $ | 35,066 |
2016 | |||
Standardized measure - beginning of year | $ | 79,028 | |
Sales and transfers of oil and gas produced, net of production costs | (4,314 | ) | |
Net changes in prices and production costs | (32,698 | ) | |
Changes in future development costs | 1,825 | ||
Revisions of previous quantity estimates | (7,477 | ) | |
Accretion of discount | 7,903 | ||
Sales of reserves | (9,201 | ) | |
Standardized measure - end of year | $ | 35,066 |
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||
(in thousands, except per share amounts, dividends and common stock prices) | ||||||||||||
2018 | ||||||||||||
Revenue | $ | 575,389 | $ | 355,704 | $ | 321,979 | $ | 501,196 | ||||
Operating income (loss) | $ | 148,274 | $ | 69,551 | $ | 65,085 | $ | 114,127 | ||||
Income (loss) from continuing operations | $ | 138,977 | $ | 27,167 | $ | 21,801 | $ | 91,604 | ||||
Income (loss) from discontinued operations | $ | (2,343 | ) | $ | (2,427 | ) | $ | (857 | ) | $ | (1,260 | ) |
Net income attributable to noncontrolling interest | $ | (3,630 | ) | $ | (2,823 | ) | $ | (3,994 | ) | $ | (3,773 | ) |
Net income (loss) available for common stock | $ | 133,004 | $ | 21,917 | $ | 16,950 | $ | 86,571 | ||||
Amounts attributable to common shareholders: | ||||||||||||
Net income (loss) from continuing operations | $ | 135,347 | $ | 24,344 | $ | 17,807 | $ | 87,831 | ||||
Net income (loss) from discontinued operations | $ | (2,343 | ) | $ | (2,427 | ) | $ | (857 | ) | $ | (1,260 | ) |
Net income (loss) available for common stock | $ | 133,004 | $ | 21,917 | $ | 16,950 | $ | 86,571 | ||||
Income (loss) per share for continuing operations - Basic | $ | 2.54 | $ | 0.46 | $ | 0.33 | $ | 1.52 | ||||
Income (loss) per share for discontinued operations - Basic | $ | (0.05 | ) | $ | (0.05 | ) | $ | (0.02 | ) | $ | (0.02 | ) |
Earnings (loss) per share - Basic | $ | 2.49 | $ | 0.41 | $ | 0.32 | $ | 1.50 | ||||
Income (loss) per share for continuing operations - Diluted | $ | 2.50 | $ | 0.45 | $ | 0.32 | $ | 1.51 | ||||
Income (loss) per share for discontinued operations - Diluted | $ | (0.04 | ) | $ | (0.05 | ) | $ | (0.02 | ) | $ | (0.02 | ) |
Earnings (loss) per share - Diluted | 2.46 | 0.40 | 0.31 | 1.49 |
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||
(in thousands, except per share amounts, dividends and common stock prices) | ||||||||||||
2017 | ||||||||||||
Revenue | $ | 547,528 | $ | 341,829 | $ | 335,611 | $ | 455,298 | ||||
Operating income (loss) | $ | 150,186 | $ | 69,796 | $ | 79,559 | $ | 117,195 | ||||
Income (loss) from continuing operations | $ | 81,715 | $ | 25,927 | $ | 32,898 | $ | 67,835 | ||||
Income (loss) from discontinued operations | $ | (1,569 | ) | $ | (616 | ) | $ | (1,300 | ) | $ | (13,614 | ) |
Net income attributable to noncontrolling interest | $ | (3,623 | ) | $ | (3,116 | ) | $ | (3,935 | ) | $ | (3,568 | ) |
Net income (loss) available for common stock | $ | 76,523 | $ | 22,195 | $ | 27,663 | $ | 50,653 | ||||
Amounts attributable to common shareholders: | ||||||||||||
Net income (loss) from continuing operations | 78,092 | 22,811 | 28,963 | 64,267 | ||||||||
Net income (loss) from discontinued operations | (1,569 | ) | (616 | ) | (1,300 | ) | (13,614 | ) | ||||
Net income (loss) available for common stock | 76,523 | 22,195 | 27,663 | 50,653 | ||||||||
Income (loss) per share for continuing operations - Basic | $ | 1.47 | $ | 0.43 | $ | 0.54 | $ | 1.21 | ||||
Income (loss) per share for discontinued operations - Basic | (0.03 | ) | (0.01 | ) | (0.02 | ) | (0.26 | ) | ||||
Earnings (loss) per share - Basic | $ | 1.44 | $ | 0.42 | $ | 0.52 | $ | 0.95 | ||||
Income (loss) per share for continuing operations - Diluted | $ | 1.42 | $ | 0.41 | $ | 0.52 | $ | 1.17 | ||||
Income (loss) per share for discontinued operations - Diluted | (0.03 | ) | (0.01 | ) | (0.02 | ) | (0.25 | ) | ||||
Earnings (loss) per share - Diluted | $ | 1.39 | $ | 0.40 | $ | 0.50 | $ | 0.92 |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
ITEM 9A. | CONTROLS AND PROCEDURES |
Management’s Report on Internal Control over Financial Reporting is presented on Page 86 of this Annual Report on Form 10-K. |
ITEM 9B. | OTHER INFORMATION |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
ITEM 11. | EXECUTIVE COMPENSATION |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Equity Compensation Plan Information | |||||||||||
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | ||||||||
(a) | (b) | (c) | |||||||||
Equity compensation plans approved by security holders | 256,111 | (1) | $ | 41.63 | (1) | 800,180 | (2) | ||||
Equity compensation plans not approved by security holders | — | $ | — | — | |||||||
Total | 256,111 | $ | 41.63 | 800,180 |
(1) | Includes 187,362 full value awards outstanding as of December 31, 2018, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares, STIP or common stock units. In addition, 235,748 shares of unvested restricted stock were outstanding as of December 31, 2018, which are not included in the above table because they have already been issued. |
(2) | Shares available for issuance are from the 2015 Omnibus Incentive Plan. The 2015 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards. |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a) | 1. | Consolidated Financial Statements |
Financial statements required under this item are included in Item 8 of Part II | ||
2. | Schedules | |
Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2018, 2017 and 2016 | ||
3. | Exhibits | |
All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto. |
3. | Exhibits |
Exhibit Number | Description |
2.1* | |
2.2* | |
2.3* | |
3.1* | |
3.2* | |
4.1* | |
4.2* | |
4.3* | |
4.4* | |
10.1*† | |
10.2*† | |
10.3*† | |
10.4*† | |
10.5† | |
10.6† |
10.7*† | |
10.8*† | |
10.9*† | |
10.10*† | |
10.11*† | |
10.12*† | |
10.13*† | |
10.14*† | |
10.15*† | |
10.16*† | |
10.17*† | |
10.18† | |
10.19*† | |
10.20* | |
10.21* | |
10.22* | |
10.23* | Coal Leases between WRDC and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10‑K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10‑K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S‑7, File No. 2‑60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10‑K for 1989). |
10.24* | Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997). |
21 | |
23.1 | |
23.2 | |
31.1 | |
31.2 | |
32.1 | |
32.2 | |
95 | |
101 | Financial Statements in XBRL Format |
* | Previously filed as part of the filing indicated and incorporated by reference herein. |
† | Indicates a board of director or management compensatory plan. |
ITEM 16. | FORM 10-K SUMMARY |
BLACK HILLS CORPORATION | |||
By: | /S/ LINDEN R. EVANS | ||
Linden R. Evans, President and Chief Executive Officer | |||
Dated: | February 19, 2019 |
/S/ LINDEN R. EVANS | Director and | February 19, 2019 |
Linden R. Evans, President | Principal Executive Officer | |
and Chief Executive Officer | ||
/S/ RICHARD W. KINZLEY | Principal Financial and | February 19, 2019 |
Richard W. Kinzley, Senior Vice President | Accounting Officer | |
and Chief Financial Officer | ||
/S/ DAVID R. EMERY | Director and | February 19, 2019 |
David R. Emery, Executive Chairman | Executive Chairman | |
/S/ MICHAEL H. MADISON | Director | February 19, 2019 |
Michael H. Madison | ||
/S/ STEVEN R. MILLS | Director | February 19, 2019 |
Steven R. Mills | ||
/S/ ROBERT P. OTTO | Director | February 19, 2019 |
Robert P. Otto | ||
/S/ REBECCA B. ROBERTS | Director | February 19, 2019 |
Rebecca B. Roberts | ||
/S/ MARK A. SCHOBER | Director | February 19, 2019 |
Mark A. Schober | ||
/S/ TERESA A. TAYLOR | Director | February 19, 2019 |
Teresa A. Taylor | ||
/S/ JOHN B. VERING | Director | February 19, 2019 |
John B. Vering | ||
/S/ THOMAS J. ZELLER | Director | February 19, 2019 |
Thomas J. Zeller |
2. | Section 2(y) of the Plan is amended to read in its entirety as follows: |
6. | Section 7.4 of the Plan is amended by revising the second and final sentence thereof to read in its entirety as follows: |
7. | Section 20 of the Plan is amended to read in its entirety as follows: |
9. | Except as explicitly set forth herein, the Plan will remain in full force and effect. |
2.1 | Account. Account means a bookkeeping account maintained by the Committee to record the payment obligation of a Participating Employer to a Participant as determined under the terms of the Plan. The Committee may maintain an Account to record the total obligation to a Participant and component Accounts to reflect amounts payable at different times and in different forms. Reference to an Account means any such Account established by the Committee, as the context requires. Accounts are intended to constitute unfunded obligations within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA. |
2.2 | Account Balance. Account Balance means, with respect to any Account, the total payment obligation owed to a Participant from such Account as of the most recent Valuation Date. |
2.3 | Affiliate. Affiliate means a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c). |
2.4 | Beneficiary. Beneficiary means a natural person, estate, or trust designated by a Participant in accordance with Section 6.4 hereof to receive payments to which a Beneficiary is entitled in accordance with provisions of the Plan. |
2.5 | Board of Directors. Board of Directors (“the Board”) means, for a Participating Employer organized as a corporation, its board of directors and for a Participating Employer organized as a limited liability company, its board of managers. |
2.6 | Business Day. Business Day means each day on which the New York Stock Exchange is open for business. |
2.7 | Change in Control. Change in Control means, with respect to a Participating Employer, any of the following events: (i) a change in the ownership of the Participating Employer, (ii) a change in the effective control of the Participating Employer, or (iii) a change in the ownership of a substantial portion of the assets of the Participating Employer. |
2.8 | Claimant. Claimant means a Participant or Beneficiary filing a claim under Article XI of this Plan. |
2.9 | Code. Code means the Internal Revenue Code of 1986, as amended from time to time. |
2.10 | Code Section 409A. Code Section 409A means section 409A of the Code, and regulations and other guidance issued by the Treasury Department and Internal Revenue Service thereunder. |
2.11 | Committee. Committee means the committee appointed by the Company’s Board of Directors to administer the Plan. |
2.12 | Company. Company means Black Hills Corporation. |
2.13 | Company Contribution. Company Contribution means a credit by a Participating Employer to a Participant’s Retirement Account as an RSP Supplemental Contribution, Supplemental Target Contribution, Supplemental Retirement Contribution, or Supplemental Matching Contribution, as applicable, in accordance with the provisions of Article V of the Plan. Unless the context clearly indicates otherwise, a reference to a Company Contribution shall include Earnings attributable to such contribution. |
2.14 | Compensation. Compensation means a Participant’s base salary, the portion of a Participant’s incentive award under the Company’s Short Term Annual Incentive Plan (“STIP”) that is payable in cash, the portion of a Participant’s Performance Share Award that is payable in cash, and such other cash compensation as may be approved by the Committee as Compensation that may be deferred under Section 4.2 of this Plan, excluding any compensation that has been previously deferred under this Plan or any other arrangement subject to Code Section 409A and excluding any compensation that is not U.S. source income. For purposes of Participant deferral elections under Article IV of this Plan, any base salary payable after the last day of a calendar year solely for services performed during the final payroll period described in Section 3401(b) of the Code containing December 31 of such year shall be treated as earned during the subsequent calendar year. |
2.15 | Compensation Deferral Agreement. Compensation Deferral Agreement means an agreement between a Participant and a Participating Employer that specifies: (i) the amount of each component of Compensation that the Participant has elected to defer to the Plan in accordance with the provisions of Article IV, and/or (ii) the Payment Schedule applicable to one or more Accounts. |
2.16 | Deferral. Deferral means a credit to a Participant’s Account(s) that records that portion of the Participant’s Compensation that the Participant has elected to defer to the Plan in accordance with the provisions of Article IV. Unless the context of the Plan clearly indicates otherwise, a reference to Deferrals includes Earnings attributable to such Deferrals. |
2.17 | Earnings. Earnings means an adjustment to the value of an Account in accordance with Article VII. |
2.18 | Effective Date. Effective Date means January 1, 2019. |
2.19 | Eligible Employee. Eligible Employee means an Employee who is selected as such by the Board of Directors pursuant to Section 3.1. |
2.20 | Employee. Employee means a common-law employee of an Employer. |
2.21 | Employer. Employer means the Company and each Affiliate. |
2.22 | ERISA. ERISA means the Employee Retirement Income Security Act of 1974, as amended from time to time. |
2.23 | Excess Compensation. Excess Compensation means the amount by which a Participant’s Total Compensation exceeds the Participant’s “Compensation” (as defined in Article I of the RSP). |
2.24 | Flex Account. Flex Account means a Separation Account or Specified Date Account established to record Deferrals credited to the Flex Account under the terms of a Participant’s Compensation Deferral Agreement. Unless the Committee specifies otherwise, a Participant may maintain no more than five (5) Flex Accounts at any one time. |
2.25 | Group 1 Participant. Group 1 Participant means a Participant who is listed on Schedule 1. |
2.26 | Group 2 Participant. Group 2 Participant means a Participant who is listed on Schedule 2. |
2.27 | Group 3 Participant. Group 3 Participant means a Participant who is listed on Schedule 3. |
2.28 | Participant. Participant means an individual described in Article III. |
2.29 | Participating Employer. Participating Employer means the Company and each Affiliate who has adopted the Plan with the consent of the Company. Each Participating Employer shall be identified on Schedule A attached hereto. |
2.30 | Payment Schedule. Payment Schedule means the date as of which payment of an Account under the Plan will commence and the form in which payment of such Account will be made. |
2.31 | Performance-Based Compensation. Performance-Based Compensation means Compensation where the amount of, or entitlement to, the Compensation is contingent on the satisfaction of pre-established organizational or individual performance criteria relating to a performance period of at least 12 consecutive months. Organizational or individual performance criteria are considered pre-established if established in writing by not later than 90 days after the commencement of the period of service to which the criteria relate, provided that the outcome is substantially uncertain at the time the criteria are established. Performance-Based Compensation shall not include any Compensation payable upon the Participant’s death or disability (as defined in Treas. Section 1.409A-1(e)) without regard to the satisfaction of the performance criteria. |
2.32 | Performance Share Award. Performance Share Award means a performance share award granted to a Participant under the Company’s Omnibus Incentive Plan (or any successor shareholder-approved incentive plan of the Company). |
2.33 | Plan. Plan means “Black Hills Corporation Post-2018 Nonqualified Deferred Compensation Plan” as documented herein and as may be amended from time to time hereafter. However, to the extent permitted or required under Code Section 409A, the term Plan may in the appropriate context also means a portion of the Plan that is treated as a single plan under Treas. Reg. Section 1.409A-1(c), |
2.34 | Plan Year. Plan Year means January 1 through December 31. |
2.35 | Retirement Account. Retirement Account means an Account established by the Committee to record Company Contributions allocated to the Retirement Account, payable to a Participant following Separation from Service in accordance with Section 6.3. |
2.36 | RSP. RSP means the Black Hills Corporation 401(k) Retirement Savings Plan, as amended from time to time. |
2.37 | RSP Supplemental Contributions. RSP Supplemental Contributions means Company Contributions equal to the amount, if any, of matching contributions that could not be allocated on behalf of a Group 2 Participant under the RSP due to the results of ADP/ACP testing for a calendar year. Group 2 Participants are listed on Schedule 2. |
2.38 | Separation Account. Separation Account means an Account established by the Committee in accordance with a Participant’s Compensation Deferral Agreement to record Deferrals allocated to such Account by the Participant and which are payable upon the Participant’s Separation from Service as set forth in Section 6.3. The Committee may limit the number of Separation Accounts that may be maintained at any one time by a Participant, as set forth in the Plan’s enrollment materials. |
2.39 | Separation from Service. Separation from Service means an Employee’s termination of employment with the Employer and all Affiliates, in such manner as to constitute a “separation from service” for purposes of Code Section 409A. |
2.40 | Specified Date Account. Specified Date Account means an Account established by the Committee to record the amounts payable in a future year as specified in the Participant’s Compensation Deferral Agreement. The Committee may limit the number of Specified Date Accounts that may be maintained at any one time by a Participant, as set forth in the Plan’s enrollment materials. |
2.41 | Substantial Risk of Forfeiture. Substantial Risk of Forfeiture has the meaning specified in Treas. Reg. Section 1.409A-1(d). |
2.42 | Supplemental Matching Contributions. Supplemental Matching Contributions means an amount equal to a percentage of a Group 2 Participant’s Excess Compensation for a Plan Year. Group 2 Participants and the applicable specified percentage for each Group 2 Participant are listed on Schedule 2. Supplemental Matching Contributions are not conditioned upon a Participant’s election to make deferrals under this Plan or under the RSP. |
2.43 | Supplemental Retirement Contributions. Supplemental Retirement Contributions means the amount by which (a) exceeds (b), where |
(a) | is the amount that would have been contributed to the RSP on behalf of a Group 3 Participant as a non-safe harbor non-elective employer contribution described in Section 7 of the RSP if such contribution were determined as a percentage of the Group 3 Participant’s Total Compensation for a Plan Year, and |
(b) | is the amount actually contributed to the RSP as a non-safe harbor non-elective employer contribution described in Section 7 of the RSP on behalf of the Group 3 Participant for the Plan Year. Group 3 Participants are listed on Schedule 3. |
2.44 | Supplemental Target Contributions. Supplemental Target Contributions means an amount equal to the specified percentage of a Group 1 Participant’s Total Compensation for a Plan Year. Group 1 Participants and the specified percentage for each such Participant are listed on Schedule 1. |
2.45 | Total Compensation. Total Compensation means ”Compensation” as defined in Article I of the RSP, but determined without regard to the Code Section 401(a)(17) limitation. |
2.46 | Unforeseeable Emergency. Unforeseeable Emergency means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant’s spouse, the Participant’s dependent (as defined in Code section 152, without regard to section 152(b)(1), (b)(2), and (d)(1)(B)), or a Beneficiary; loss of the Participant’s property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance, for example, as a result of a natural disaster); or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The types of events which may qualify as an Unforeseeable Emergency may be limited by the Committee. |
2.47 | Valuation Date. Valuation Date means each Business Day. |
3.1 | Eligibility and Participation. In order to be eligible for participation in the Plan as an “Eligible Employee”, an Employee must be selected by the Board of Directors. For each enrollment, the Board of Directors, in its sole and absolute discretion, shall determine eligibility for participation from among management or highly compensated employees of the Employer who are officers appointed by the Board of Directors in accordance with the purposes of the Plan and shall determine the amount and type of Company Contributions, if any, to be made on behalf of any Participant. An Employee ceases to be eligible for participation in the Plan upon his Separation from Service or, if earlier, the date his participation is discontinued by the Chief Executive Officer, provided that, to the extent required to comply with Section 409A of the Code, such Employee’s |
3.2 | Duration. Only Eligible Employees may submit Compensation Deferral Agreements during an enrollment and receive Company Contributions during the Plan Year. A Participant who is no longer an Eligible Employee but has not incurred a Separation from Service will not be allowed to submit Compensation Deferral Agreements but may otherwise exercise all of the rights of a Participant under the Plan with respect to his or her Account(s). On and after a Separation from Service, a Participant shall remain a Participant as long as his or her Account Balance is greater than zero (0). All Participants, regardless of employment status, will continue to be credited with Earnings and during such time may continue to make allocation elections as provided in Section 7.4. An individual shall cease being a Participant in the Plan when his Account has been reduced to zero (0). |
3.3 | Rehires. An Eligible Employee who Separates from Service and who subsequently resumes performing services for an Employer in the same calendar year (regardless of eligibility) will have his or her Compensation Deferral Agreement for such year, if any, reinstated, but his or her eligibility to participate in the Plan in years subsequent to the year of rehire shall be governed by the provisions of Section 3.1. |
(a) | A Participant may make an initial election to defer Compensation by submitting a Compensation Deferral Agreement during the enrollment periods established by the Committee and in the manner specified by the Committee, but in any event, in accordance with Section 4.2. Unless an earlier date is specified in the Compensation Deferral Agreement, deferral elections with respect to a Compensation source (such as salary, bonus or other Compensation) become irrevocable on the latest date applicable to such Compensation source under Section 4.2. |
(b) | A Compensation Deferral Agreement that is not timely filed with respect to a service period or component of Compensation, or that is submitted by a Participant who Separates from Service prior to the latest date such agreement would become irrevocable under Section 409A, shall be considered null and void and shall not take effect with respect to such item of Compensation. The Committee may modify or revoke any Compensation Deferral Agreement prior to the date the election becomes irrevocable under the rules of Section 4.2. |
(c) | The Committee may permit different deferral amounts for each component of Compensation and may establish a minimum or maximum deferral amount for each such component. Unless otherwise specified by the Committee in the Compensation Deferral Agreement, Participants may defer up to fifty percent (50%) of their base salary, up to one hundred percent (100%) of the cash portion of their STIP bonus earned during a Plan Year, and up to one hundred percent (100%) of the cash portion of their Performance Share Awards that become earned and vested in accordance with the terms of the applicable Performance Share Award. |
(d) | Deferrals of cash Compensation shall be calculated with respect to the gross cash Compensation payable to the Participant prior to any deductions or withholdings, but shall be reduced by the Committee as necessary so as not to exceed 100% of the cash Compensation of the Participant remaining after deduction of all required income and employment taxes, required employee benefit deductions, deferrals to 401(k) plans and other deductions required by law. Changes to payroll withholdings that affect the amount of Compensation being deferred to the Plan shall be allowed only to the extent permissible under Code Section 409A. |
(e) | The Participant shall specify on his or her Compensation Deferral Agreement the amount of Deferrals and whether to allocate Deferrals to a Separation Account or to one or more Specified Date Accounts. |
(a) | Initial Eligibility. The Committee may permit an Eligible Employee to defer Compensation earned in the first year of eligibility for participation in the Plan and any other nonqualified deferred compensation plan or arrangement that would be aggregated with the Plan under Section 409A of the Code. The Compensation Deferral Agreement must be filed within 30 days after attaining Eligible Employee status and becomes irrevocable not later than the 30th day. |
(b) | Prior Year Election. Except as otherwise provided in this Section 4.2, the Committee may permit an Eligible Employee to defer Compensation, or make a payment election with respect to Compensation, by filing a Compensation Deferral Agreement during the enrollment period established by the Committee and ending no later than December 31 of the year prior to the year in which the Compensation to be deferred is earned. A Compensation Deferral Agreement filed under this paragraph shall become irrevocable with respect to such Compensation not later than the December 31 filing deadline. |
(c) | Performance-Based Compensation. The Committee may permit an Eligible Employee to defer Compensation which qualifies as Performance-Based Compensation by filing a Compensation Deferral Agreement no later than the date that is six months before the end of the applicable performance period, provided that: |
(i) | the Participant performs services continuously from the later of the beginning of the performance period or the date the performance criteria are established through the date the Compensation Deferral Agreement is submitted; and |
(ii) | the Compensation is not readily ascertainable as of the date the Compensation Deferral Agreement is filed. |
(d) | Short-Term Deferrals. The Committee may permit Compensation that meets the definition of a “short-term deferral” described in Treas. Reg. Section 1.409A-1(b)(4) to be deferred in accordance with the rules of Section 6.9, applied as if the date the Substantial Risk of Forfeiture lapses is the date payments were originally scheduled to commence, provided, however, that the provisions of Section 6.9(b) shall not apply to payments attributable to a Change in Control. A Compensation Deferral Agreement submitted in accordance with this paragraph becomes irrevocable on the latest date it could be submitted under Section 6.9. |
(e) | Certain Forfeitable Rights. With respect to a legally binding right to a payment in a subsequent year that is subject to a forfeiture condition requiring the Participant’s continued services for a period of at least 12 months from the date the Participant obtains the legally binding right, the Committee may permit an Eligible Employee to defer such Compensation, or make a payment election with respect to such Compensation, by filing a Compensation Deferral Agreement on or before the 30th day after the legally binding right to the Compensation accrues, provided that the Compensation Deferral Agreement is submitted at least 12 months in advance of the earliest date on which the forfeiture condition could lapse. The Compensation Deferral Agreement described in this paragraph becomes irrevocable not later than such 30th day. If the forfeiture condition applicable to the payment lapses before the end of such 12-month period as a result of the Participant’s death or disability (as defined in Treas. Reg. Section 1.409A-3(i)(4)) or upon a Change in Control, the Compensation Deferral Agreement will be void unless it would be considered timely under another rule described in this Section. |
(f) | “Evergreen” Deferral Elections. The Committee, in its discretion, may provide, if so specified in the applicable Compensation Deferral Agreement, that Compensation Deferral Agreements will continue in effect for subsequent years or performance periods by communicating that intention to Participants in writing prior to the date Compensation Deferral Agreements become irrevocable under this Section 4.2. An evergreen Compensation Deferral Agreement may be revoked or modified in writing prospectively by the Participant or the Committee with respect to Compensation for which such election remains revocable under this Section 4.2. |
4.3 | Allocation of Deferrals. A Compensation Deferral Agreement may allocate Deferrals to one or more Flex Accounts, each of which shall be either a Separation Account or a Specified Date Account. The Committee may, in its discretion, establish in a written communication during enrollment a minimum deferral period for the establishment of a Specified Date Account (for example, the fourth Plan Year following the year Compensation is first allocated to such Accounts). In the event a Participant’s Compensation Deferral Agreement allocates a component of Compensation to a Specified Date Account that commences payment in the year such Compensation is earned, the Compensation Deferral Agreement shall be deemed to allocate the Deferral to the Participant’s Specified Date Account having the next earliest payment year. If the Participant has no other Specified Date Accounts, the Committee will allocate the Deferral to the Retirement Account. |
4.4 | Deductions from Pay. The Committee has the authority to determine the payroll practices under which any component of Compensation subject to a Compensation Deferral Agreement will be deducted from a Participant’s Compensation. |
4.5 | Vesting. Participant Deferrals of cash Compensation shall be 100% vested at all times. Deferrals of vesting awards of Compensation shall become vested in accordance with the provisions of the underlying award. |
4.6 | Cancellation of Deferrals. The Committee may cancel a Participant’s Deferrals: (i) for the balance of the Plan Year in which an Unforeseeable Emergency occurs, and (ii) during periods in which the Participant incurs a “disability,” meaning that the Participant is unable to perform the duties of his or her position or any substantially similar position due to a mental or physical impairment that can be expected to result in death or last for a continuous period of at least six months, provided cancellation occurs by the later of the end of the calendar year or the 15th day of the third month following the date the Participant incurs the disability (as defined in this Section 4.6). |
5.1 | Company Contributions. Company Contributions shall be made to a Participant’s Retirement Account in the form of RSP Supplemental Contributions, Supplemental Target Contributions, Supplemental Retirement Contributions, and/or Supplemental Matching Contributions, as applicable, in accordance with this Article V. |
(a) | Supplemental Matching Contributions. As of the last day of each pay period in which a Group 2 Participant receives Excess Compensation, the Company shall credit to the Group 2 Participant’s Retirement Account the amount of the Supplemental Matching Contributions determined in accordance with the terms of the Plan. |
(b) | Supplemental Target Contributions. As of the last day of each Plan Year, the Company shall credit to each Group 1 Participant’s Retirement Account the amount of the Supplemental Target Contribution determined in accordance with the terms of the Plan. Notwithstanding the foregoing, the Board retains discretion to determine which Participants are Group 1 Participants and the amount, if any, of Supplemental Target Contributions to be made with respect to individuals who become Group 1 Participants. |
(c) | Supplemental Retirement Contributions. As of the last day of each pay period in which a Group 3 Participant receives Excess Compensation, the Company shall credit to the Group |
(d) | RSP Supplemental Contributions. After the end of each Plan Year, the Company shall determine the amount, if any, of RSP Supplemental Contributions to which a Participant is entitled and shall credit such amount to the Participant’s Retirement Account as of the last day of such Plan Year. |
5.2 | Vesting. Company Contributions vest according the schedule specified by the Committee on or before the time the contributions are made. |
No. of Years of Service: | Vested % |
1 Years | 20% |
2 Years | 40 % |
3 Years | 60 % |
4 Years | 80 % |
5 Years | 100% |
6.1 | General Rules. A Participant’s Accounts become payable upon the first to occur of the payment events applicable to such Account under (i) Sections 6.2 or 6.3 (as elected, and subject to the $100,000 minimum balance requirement) and (ii) Sections 6.4 through 6.6. |
6.2 | Specified Date Accounts. |
6.3 | Separation from Service. Upon a Participant’s Separation from Service other than death, the Participant is entitled to receive his or her vested Retirement Account and vested Separation Accounts. |
(a) | Commencement. Each vested Retirement Account and all Separation Accounts will commence payment in the calendar year next following the calendar year in which the Participant’s Separation from Service occurs. Notwithstanding the foregoing, all Accounts, including any unpaid Specified Date Accounts will be payable upon Separation from Service if the combined Account Balance for a Participant is not more than $100,000 as of his or her Separation from Service. |
(b) | Form of Payment. The vested Retirement Account and Separation Accounts will be paid in a single lump sum unless the Participant elected with respect to an Account to receive annual installments up to 10 years. If the combined vested Account Balances of all of a Participant’s Accounts on the date of a Participant’s Separation from Service is not more than $100,000, all Accounts will be paid in a lump sum, without regard to the provisions of Section 6.2 and without regard to any other election the Participant may have made for such Accounts. |
(c) | Mandatory Delay for Specified Employees. Notwithstanding any other provision of this Plan, to the extent required to comply with Code Section 409A, payment to a Participant who is a “specified employee” as defined in Code Section 409A(a)(2)(B) will commence no earlier than six months following his or her Separation from Service. |
6.4 | Death. Notwithstanding anything to the contrary in this Article VI, upon the death of the Participant (regardless of whether such Participant is an Employee at the time of death), all remaining vested Account Balances shall be paid to his or her Beneficiary in a single lump sum no later than December 31 of the calendar year following the year of the Participant’s death. |
(a) | Designation of Beneficiary in General. The Participant shall designate a Beneficiary in the manner and on such terms and conditions as the Committee may prescribe. No such designation shall become effective unless filed with the Committee during the Participant’s lifetime. Any designation shall remain in effect until a new designation is filed with the |
(b) | No Beneficiary. If a designated Beneficiary does not survive the Participant, or if there is no valid Beneficiary designation, amounts payable under the Plan upon the death of the Participant shall be paid to the Participant’s spouse, or if there is no surviving spouse, then to the duly appointed and currently acting personal representative of the Participant’s estate. |
6.5 | Unforeseeable Emergency. A Participant who experiences an Unforeseeable Emergency may submit a written request to the Committee to receive payment of all or any portion of his or her vested Accounts. If the emergency need cannot be relieved by cessation of Deferrals to the Plan, the Committee may approve an emergency payment therefrom not to exceed the amount reasonably necessary to satisfy the need, taking into account the additional compensation that is available to the Participant as the result of cancellation of deferrals to the Plan, including amounts necessary to pay any taxes or penalties that the Participant reasonably anticipates will result from the payment. The amount of the emergency payment shall be subtracted from the Separation Accounts and then from the Specified Date Accounts, starting with the Account having the latest commencement date until fully distributed, then continuing in this manner with the next latest Account until the full amount of the distribution is made. Emergency payments shall be paid in a single lump sum within the 90-day period following the date the payment is approved by the Committee. The Committee may specify that Deferrals will be distributed before any Company Contributions. |
6.6 | Administrative Cash-Out of Small Balances. Notwithstanding anything to the contrary in this Article VI, the Committee may at any time and without regard to whether a payment event has occurred, direct in writing an immediate lump sum payment of the Participant’s Accounts if the balance of such Accounts, combined with any other amounts required to be treated as deferred under a single plan pursuant to Code Section 409A, does not exceed the applicable dollar amount under Code Section 402(g)(1)(B), provided any other such aggregated amounts are also distributed in a lump sum at the same time. |
6.7 | Acceleration of or Delay in Payments. Notwithstanding anything to the contrary in this Article VI, the Board, in its sole and absolute discretion, may elect to accelerate the time or form of payment of an Account, provided such acceleration is permitted under Treas. Reg. Section 1.409A-3(j)(4). The Board may also, in its sole and absolute discretion, delay the time for payment of an Account, to the extent permitted under Treas. Reg. Section 1.409A-2(b)(7). |
6.8 | Rules Applicable to Installment Payments. If a Payment Schedule specifies installment payments, payments will be made beginning as of the payment commencement date for such installments and shall continue to be made in each subsequent payment period until the number of installment payments specified in the Payment Schedule has been paid. The amount of each installment payment shall be determined by dividing (a) by (b), where (a) equals the Account Balance as of the last Valuation Date in the month |
6.9 | Modifications to Payment Schedules. A Participant may modify the Payment Schedule elected by him or her with respect to an Account, consistent with the permissible Payment Schedules available under the Plan for the applicable payment event, provided such modification complies with the requirements of this Section 6.9. |
(a) | Time of Election. The modification election must be submitted to the Committee not less than 12 months prior to the date payments would have commenced under the Payment Schedule in effect prior to modification (the “Prior Election”). |
(b) | Date of Payment under Modified Payment Schedule. The date payments are to commence under the modified Payment Schedule must be no earlier than five years after the date payment would have commenced under the Prior Election. Under no circumstances may a modification election result in an acceleration of payments in violation of Code Section 409A. If the Participant modifies only the form, and not the commencement date for payment, payments shall commence on the fifth anniversary of the date payment would have commenced under the Prior Election. |
(c) | Irrevocability; Effective Date. A modification election is irrevocable when filed and becomes effective 12 months after the filing date. |
(d) | Effect on Accounts. An election to modify a Payment Schedule is specific to the Account or payment event to which it applies, and shall not be construed to affect the Payment Schedules or payment events of any other Accounts. A modification election has no effect on the lump sum cash out for Account Balances at or below $100,000 as provided in Section 6.3. |
7.1 | Valuation. Deferrals shall be credited to appropriate Accounts on the date such Compensation would have been paid to the Participant absent the Compensation Deferral Agreement. Valuation of Accounts shall be performed under procedures approved by the Committee. |
7.2 | Earnings Credit. Each Account will be credited with Earnings on each Business Day, based upon the Participant’s investment allocation among a menu of investment options selected in advance by the Board, in accordance with the provisions of this Article VII (“investment allocation”). |
7.3 | Investment Options. Investment options will be determined by the Board. The Board, in its sole discretion, shall be permitted to add or remove investment options from the Plan menu from time to time, provided that any such additions or removals of investment |
7.4 | Investment Allocations. A Participant’s investment allocation constitutes a deemed, not actual, investment among the investment options comprising the investment menu. At no time shall a Participant have any real or beneficial ownership in any investment option included in the investment menu, nor shall the Participating Employer or any trustee acting on its behalf have any obligation to purchase actual securities as a result of a Participant’s investment allocation. A Participant’s investment allocation shall be used solely for purposes of adjusting the value of a Participant’s Account Balances. |
7.5 | Unallocated Deferrals and Accounts. If the Participant fails to make an investment allocation with respect to an Account, such Account shall be invested in an investment option, the primary objective of which is the preservation of capital, as determined by the Committee. |
7.6 | Valuations Final After 180 Days. The Participant shall have 180 days following the Valuation Date on which the Participant failed to receive the full amount of Earnings and to file a claim under Article XI for the correction of such error. |
8.1 | Plan Administration. This Plan shall be administered by the Committee which shall have discretionary authority to make, interpret and enforce all appropriate rules and regulations for the administration of this Plan and to utilize its discretion to decide or resolve any and all questions, including but not limited to eligibility for benefits and interpretations of this Plan and its terms, as may arise in connection with the Plan. Claims for benefits shall be filed with the Committee and resolved in accordance with the claims procedures in Article XI. |
8.2 | Withholding. The Employer may withhold or cause to be withheld from any amounts payable under the Plan all federal, state, local and other taxes as shall be legally required to be withheld. Further, with respect to any federal, state, local and other taxes that may be required to be withheld at any time as a result of the crediting, vesting or payment of benefits under the Plan, the Employer shall have the right to (a) require a Participant to pay or provide for payment of any such taxes, or (b) withhold any such taxes from any compensation otherwise payable in cash to the Participant. |
8.3 | Indemnification. The Participating Employers shall indemnify and hold harmless each employee, officer, director, agent or organization, to whom or to which are delegated duties, responsibilities, and authority under the Plan or otherwise with respect to administration of the Plan, including, without limitation, the Committee, its delegees and its agents, against all claims, liabilities, fines and penalties, and all expenses reasonably incurred by or imposed upon him or it (including but not limited to reasonable attorney fees) which arise as a result of his or its actions or failure to act in connection with the operation and administration of the Plan to the extent lawfully allowable and to the extent that such claim, liability, fine, penalty, or expense is not paid for by liability insurance purchased or paid for by the Participating Employer. Notwithstanding the foregoing, the Participating Employer shall not indemnify any person or organization if his or its actions or failure to act are due to gross negligence or willful misconduct or for any such amount incurred through any settlement or compromise of any action unless the Participating Employer consents in writing to such settlement or compromise. |
8.4 | Delegation of Authority. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with legal counsel who shall be legal counsel to the Company. |
8.5 | Binding Decisions or Actions. The decision or action of the Committee in respect of any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations thereunder shall be final and conclusive and binding upon all persons having any interest in the Plan. |
9.1 | Amendment and Termination. The Company may at any time and from time to time amend the Plan or may terminate the Plan as provided in this Article IX. Each Participating Employer may also terminate its participation in the Plan. |
9.2 | Amendments. The Company, by action taken by its Board of Directors, may amend the Plan at any time and for any reason, provided that any such amendment shall not reduce the vested Account Balances of any Participant accrued as of the date of any such amendment or restatement (as if the Participant had incurred a voluntary Separation from Service on such date). The Board of Directors of the Company may delegate to the Committee the authority to amend the Plan without the consent of the Board of Directors for the purpose of: (i) conforming the Plan to the requirements of law; (ii) facilitating the administration of the Plan; (iii) clarifying provisions based on the Committee’s interpretation of the Plan documents; and (iv) making such other amendments as the Board of Directors may authorize. No amendment is needed to revise the list of Participating Employers set forth on Schedule A attached hereto. |
9.3 | Termination. The Company, by action taken by its Board of Directors, may terminate the Plan and pay Participants and Beneficiaries their Account Balances in a single lump sum at any time, to the extent and in accordance with Treas. Reg. Section 1.409A-3(j)(4)(ix). |
9.4 | Accounts Taxable Under Code Section 409A. The Plan is intended to constitute a plan of deferred compensation that meets the requirements for deferral of income taxation under Code Section 409A. The Committee, pursuant to its authority to interpret the Plan, may sever from the Plan or any Compensation Deferral Agreement any provision or exercise of a right that otherwise would result in a violation of Code Section 409A. |
10.1 | General Assets. Obligations established under the terms of the Plan may be satisfied from the general funds of the Participating Employers, or a trust described in this Article X. No Participant, spouse or Beneficiary shall have any right, title or interest whatever in assets of the Participating Employers. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship, between the Participating Employers and any Employee, spouse, or Beneficiary. To the extent that any person acquires a right to receive payments hereunder, such rights are no greater than the right of an unsecured general creditor of the Participating Employer. |
10.2 | Rabbi Trust. A Participating Employer may, in its sole discretion, establish a grantor trust, commonly known as a rabbi trust, as a vehicle for accumulating assets to pay benefits under the Plan. Payments under the Plan may be paid from the general assets of the Participating Employer or from the assets of any such rabbi trust. Payment from any such source shall reduce the obligation owed to the Participant or Beneficiary under the Plan. |
11.1 | Filing a Claim. Any controversy or claim arising out of or relating to the Plan shall be filed in writing with the Committee which shall make all determinations concerning such claim. Any claim filed with the Committee and any decision by the Committee denying such claim shall be in writing and shall be delivered to the Participant or Beneficiary filing the claim (the “Claimant”). Notice of a claim for payments shall be delivered to the Committee within 90 days of the latest date upon which the payment could have been timely made in accordance with the terms of the Plan and Code Section 409A, and if not paid, the Participant or Beneficiary must file a claim under this Article XI not later than 180 days after such latest date. If the Participant or Beneficiary fails to file a timely claim, the Participant forfeits any amounts to which he or she may have been entitled to receive under the claim. |
(a) | In General. Notice of a denial of benefits (other than claims based on disability) will be provided within 90 days of the Committee’s receipt of the Claimant's claim for |
(b) | Disability Benefits. Notice of denial of claims based on disability will be provided within forty-five (45) days of the Committee’s receipt of the Claimant’s claim for disability benefits. If the Committee determines that it needs additional time to review the disability claim, the Committee will provide the Claimant with a notice of the extension before the end of the initial 45-day period. If the Committee determines that a decision cannot be made within the first extension period due to matters beyond the control of the Committee, the time period for making a determination may be further extended for an additional 30 days. If such an additional extension is necessary, the Committee shall notify the Claimant prior to the expiration of the initial 30-day extension. Any notice of extension shall indicate the circumstances necessitating the extension of time, the date by which the Committee expects to furnish a notice of decision, the specific standards on which such entitlement to a benefit is based, the unresolved issues that prevent a decision on the claim and any additional information needed to resolve those issues. A Claimant will be provided a minimum of 45 days to submit any necessary additional information to the Committee. In the event that a 30-day extension is necessary due to a Claimant’s failure to submit information necessary to decide a claim, the period for furnishing a notice of decision shall be tolled from the date on which the notice of the extension is sent to the Claimant until the earlier of the date the Claimant responds to the request for additional information or the response deadline. |
(c) | Contents of Notice. If a claim for benefits is completely or partially denied, notice of such denial shall be in writing. Any electronic notification shall comply with the standards imposed by Department of Labor Regulation 29 CFR 2520.104b-1(c)(1)(i), (iii), and (iv). The notice of denial shall set forth the specific reasons for denial in plain language. The notice shall: (i) cite the pertinent provisions of the Plan document, and (ii) explain, where appropriate, how the Claimant can perfect the claim, including a description of any additional material or information necessary to complete the claim and why such material or information is necessary. The claim denial also shall include an explanation of the claims review procedures and the time limits applicable to such procedures, including the right to appeal the decision, the deadline by which such appeal must be filed and a statement of the Claimant’s right to bring a civil action under Section 502(a) of ERISA following an adverse decision on appeal and the specific date by which such a civil action must commence under Section 11.4. |
11.2 | Appeal of Denied Claims. A Claimant whose claim has been completely or partially denied shall be entitled to appeal the claim denial by filing a written appeal with a committee designated to hear such appeals (the “Appeals Committee”). A Claimant who timely requests a review of the denied claim (or his or her authorized representative) may review, upon request and free of charge, copies of all documents, records and other information relevant to the denial and may submit written comments, documents, records and other information relating to the claim to the Appeals Committee. All written comments, documents, records, and other information shall be considered “relevant” if the information: (i) was relied upon in making a benefits determination, (ii) was submitted, considered or generated in the course of making a benefits decision regardless of whether it was relied upon to make the decision, or (iii) demonstrates compliance with administrative processes and safeguards established for making benefit decisions. The review shall take into account all comments, documents, records, and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The Appeals Committee may, in its sole discretion and if it deems appropriate or necessary, decide to hold a hearing with respect to the claim appeal. |
(a) | In General. Appeal of a denied benefits claim (other than a disability benefits claim) must be filed in writing with the Appeals Committee no later than 60 days after receipt of the written notification of such claim denial. The Appeals Committee shall make its decision regarding the merits of the denied claim within 60 days following receipt of the appeal (or within 120 days after such receipt, in a case where there are special circumstances requiring extension of time for reviewing the appealed claim). If an extension of time for reviewing the appeal is required because of special circumstances, written notice of the extension shall be furnished to the Claimant prior to the commencement of the extension. The notice will indicate the special circumstances requiring the extension of time and the date by which the Appeals Committee expects to render the determination on review. The review will take into account comments, documents, records and other information submitted by the Claimant relating to the claim without regard to whether such information was submitted or considered in the initial benefit determination. |
(b) | Disability Benefits. Appeal of a denied disability benefits claim must be filed in writing with the Appeals Committee no later than 180 days after receipt of the written notification of such claim denial. The review shall be conducted in accordance with applicable Department of Labor regulations. |
(c) | Contents of Notice. If a benefits claim is completely or partially denied on review, notice of such denial shall be in writing. Any electronic notification shall comply with the standards imposed by Department of Labor Regulation 29 CFR 2520.104b-1(c)(1)(i), (iii), and (iv). Such notice shall set forth the reasons for denial in plain language. |
11.3 | Legal Action. A Claimant may not bring any legal action relating to a claim for benefits under the Plan unless and until the Claimant has followed the claims procedures under the Plan and exhausted his or administrative remedies under Sections 11.1 and 11.2. No such legal action may be brought more than twelve (12) months following the notice of denial of benefits under Section 11.2, or if no appeal is filed by the applicable appeals deadline, twelve (12) months following the appeals deadline. |
11.4 | Discretion of Appeals Committee. All interpretations, determinations and decisions of the Appeals Committee with respect to any claim shall be made in its sole discretion, and shall be final and conclusive. |
12.1 | Assignment. No interest of any Participant, spouse or Beneficiary under this Plan and no benefit payable hereunder shall be assigned as security for a loan, and any such |
12.2 | No Legal or Equitable Rights or Interest. No Participant or other person shall have any legal or equitable rights or interest in this Plan that are not expressly granted in this Plan. Participation in this Plan does not give any person any right to be retained in the service of the Participating Employer. The right and power of a Participating Employer to dismiss or discharge an Employee is expressly reserved. The Participating Employers make no representations or warranties as to the tax consequences to a Participant or a Participant’s beneficiaries resulting from a deferral of income pursuant to the Plan. |
12.3 | No Employment Contract. Nothing contained herein shall be construed to constitute a contract of employment between an Employee and a Participating Employer. |
12.4 | Notice. Any notice or filing required or permitted to be delivered to the Committee under this Plan shall be delivered in writing, in person, or through such electronic means (such as secure facsimile) as is established by the Committee. Notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Written transmission shall be sent by certified mail to: |
12.5 | Headings. The headings of Sections are included solely for convenience of reference, and if there is any conflict between such headings and the text of this Plan, the text shall control. |
12.6 | Invalid or Unenforceable Provisions. If any provision of this Plan shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof and the Committee may elect in its sole discretion to construe such invalid or unenforceable provisions in a manner that conforms to applicable law or as if such provisions, to the extent invalid or unenforceable, had not been included. |
12.7 | Lost Participants or Beneficiaries. Any Participant or Beneficiary who is entitled to a benefit from the Plan has the duty to keep the Committee advised of his or her current |
12.8 | Facility of Payment to a Minor. If a distribution is to be made to a minor, or to a person who is otherwise incompetent, then the Committee may, in its discretion, make such distribution: (i) to the legal guardian, or if none, to a parent of a minor payee with whom the payee maintains his or her residence, or (ii) to the conservator or committee or, if none, to the person having custody of an incompetent payee. Any such distribution shall fully discharge the Committee, the Company, and the Plan from further liability on account thereof. |
12.9 | Governing Law. To the extent not preempted by ERISA, the laws of the State of South Dakota shall govern the construction and administration of the Plan. |
12.10 | Compliance With Code Section 409A; No Guarantee. This Plan is intended to be administered in compliance with Code Section 409A and each provision of the Plan shall be interpreted consistent with Code Section 409A. Although the Company intends for the Plan to comply with Code Section 409A, the tax treatment of benefits under the Plan is not warranted or guaranteed, and neither the Company, any other Employer, the Committee, nor the Board of Directors (nor any of their delegates) shall be held liable for any taxes, interest, penalties or other monetary amounts that may be owed by any Participant, Beneficiary or other taxpayer claiming benefits hereunder. No Employer shall have any legal obligation to a Participant with respect to taxes imposed under Code Section 409A. |
Name | Percentage of Total Compensation |
Scott Buchholz | 14.0% |
Linn Evans | 20.0% |
Brian Iverson | 8.0% |
Rich Kinzley | 17.5% |
Perry Krush | 14.5% |
Jennifer Landis | 8.0% |
Mark Lux | 8.0% |
Marne Miller Jones | 8.0% |
Esther Newbrough | 8.0% |
Kimberly Nooney | 8.0% |
Ivan Vancas | 8.0% |
Stuart Wevik | 8.0% |
Name | Percentage of Total Compensation |
Scott Buchholz | 6% |
Linn Evans | 6% |
Brian Iverson | 6% |
Rich Kinzley | 6% |
Perry Krush | 6% |
Jennifer Landis | 6% |
Mark Lux | 6% |
Marne Miller Jones | 6% |
Esther Newbrough | 6% |
Kimberly Nooney | 6% |
Ivan Vancas | 6% |
Stuart Wevik | 6% |
Name |
Linn Evans |
Brian Iverson |
Rich Kinzley |
Jennifer Landis |
Mark Lux |
Marne Miller Jones |
Esther Newbrough |
Kimberly Nooney |
Ivan Vancas |
1. | RECITALS. |
2. | AMENDMENTS TO SECTION 4. ADDITIONS TO ACCOUNTS. |
b. | For each of the applicable Quarter Periods designated in the table below, each Participant shall be entitled to a quarterly addition to their Account in the amount determined by dividing the sum of the applicable Quarterly Value by the market price of the Company common stock on the last trading day of the applicable Quarterly Period that the Participant is eligible for benefits. |
Quarterly Period | Quarterly Value |
December 1, 2007 - February 29, 2008 | $11,333.33 |
March 1, 2008 - May 31, 2008 through September 1, 2010 - November 30, 2010 | $12,500.00 |
December 1, 2010 - February 28, 2011 | $14,166.67 |
March 1, 2011 - May 31, 2011 through September 1, 2012 - November 30, 2012 | $15,000.00 |
December 1, 2012 - February 28, 2013 | $17,500.00 |
March 1, 2013 - May 31, 2013 through September 1, 2014 - November 30, 2014 | $18,750.00 |
December 1, 2014 - February 28, 2015 | $19,583.33 |
March 1, 2015 - May 31, 2015 through September 1, 2016 - November 30, 2016 | $20,000.00 |
December 1, 2016 - February 28, 2017 | $21,666.67 |
March 1, 2017 - May 31, 2017 through September 1, 2017 - November 30, 2017 | $22,500.00 |
December 1, 2017 - February 28, 2018 | $22,708.33 |
March 1, 2018 - May 31, 2018 through September 1, 2018 - November 30, 2018 | $23,125.00 |
December 1, 2018 - February 28, 2019 | $25,208.33 |
March 1, 2019 - May 31, 2019 through Quarterly Periods thereafter | $26,250.00 |
3. | NO OTHER CHANGES. |
Subsidiary Name | State of Origin | |
1. | Black Hills Cabresto Pipeline, LLC | Delaware |
2. | Black Hills Colorado Electric, LLC * | Delaware |
3. | Black Hills Colorado Gas, Inc. * | Colorado |
4. | Black Hills Colorado IPP, LLC * | South Dakota |
5. | Black Hills Colorado Wind, LLC | Delaware |
6. | Black Hills Electric Generation, LLC * | South Dakota |
7. | Black Hills Energy Arkansas, Inc. * | Arkansas |
8. | Black Hills Energy Services Company * | Colorado |
9. | Black Hills Exploration and Production, Inc. * | Wyoming |
10. | Black Hills Gas, Inc. | Delaware |
11. | Black Hills Gas, LLC | Delaware |
12. | Black Hills Gas Distribution, LLC * | Delaware |
13. | Black Hills Gas Holdings, LLC | Delaware |
14. | Black Hills Gas Parent Holdings II, Inc. | Delaware |
15. | Black Hills Gas Resources, Inc. * | Colorado |
16. | Black Hills/Iowa Gas Utility Company, LLC * | Delaware |
17. | Black Hills/Kansas Gas Utility Company, LLC * | Kansas |
18. | Black Hills Midstream, LLC | South Dakota |
19. | Black Hills/Nebraska Gas Utility Company, LLC * | Delaware |
20. | Black Hills Non-regulated Holdings, LLC | South Dakota |
21. | Black Hills Northwest Wyoming Gas Utility Company, LLC * | Wyoming |
22. | Black Hills Plateau Production, LLC * | Delaware |
23. | Black Hills Power, Inc. * | South Dakota |
24. | Black Hills Service Company, LLC * | South Dakota |
25. | Black Hills Shoshone Pipeline, LLC * | Wyoming |
26. | Black Hills Utility Holdings, Inc. * | South Dakota |
27. | Black Hills Wyoming, LLC | Wyoming |
28. | Cheyenne Light, Fuel and Power Company * | Wyoming |
29. | Generation Development Company, LLC | South Dakota |
30. | Mallon Oil Company, Sucursal Costa Rica | Costa Rica |
31. | N780BH, LLC | South Dakota |
32. | Rocky Mountain Natural Gas LLC * | Colorado |
33. | Wyodak Resources Development Corp. * | Delaware |
CAWLEY, GILLESPIE & ASSOCIATES, INC. | |
/S/ J. ZANE MEEKINS | |
J. Zane Meekins | |
Executive Vice President | |
Fort Worth, Texas | |
February 19, 2019 |
1. | I have reviewed this Annual Report on Form 10-K of Black Hills Corporation; | |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: | |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting. | |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): | |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and | |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. | |
Date: | February 19, 2019 | ||
/S/ LINDEN R. EVANS | |||
Linden R. Evans | |||
President and Chief Executive Officer |
1. | I have reviewed this Annual Report on Form 10-K of Black Hills Corporation; | |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; | |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; | |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: | |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting. | |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): | |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and | |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. | |
Date: | February 19, 2019 | ||
/S/ RICHARD W. KINZLEY | |||
Richard W. Kinzley | |||
Senior Vice President and Chief Financial Officer |
(1) | The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and | |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. | |
Date: | February 19, 2019 | ||
/S/ LINDEN R. EVANS | |||
Linden R. Evans | |||
President and Chief Executive Officer |
(1) | The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and | |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. | |
Date: | February 19, 2019 | ||
/S/ RICHARD W. KINZLEY | |||
Richard W. Kinzley | |||
Senior Vice President and Chief Financial Officer |
• | Total number of violations of mandatory health and safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA; |
• | Total number of orders issued under section 104(b) of the Mine Act; |
• | Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health and safety standards under section 104(d) of the Mine Act; |
• | Total number of imminent danger orders issued under section 107(a) of the Mine Act; and |
• | Total dollar value of proposed assessments from MSHA under the Mine Act. |
Mine/MSHA Identification | Mine Act Section 104 S&S Citations issued during twelve months ended | Mine Act Section 104(b) | Mine Act Section 104(d) Citations and | Mine Act Section 110(b)(2) | Mine Act Section 107(a) Imminent Danger | Total Dollar Value of Proposed MSHA | Total Number of Mining Related | Received Notice of Potential to Have Pattern Under Section | Legal Actions Pending as of Last Day of | Legal Actions Initiated During | Legal Actions Resolved During | ||
Number | December 31 | Orders | Orders | Violations | Orders | Assessments | Fatalities | 104(e) | Period | Period | Period | ||
2018 | (#) | (#) | (#) | (#) | (a) | (#) | (yes/no) | (#) | (#) | (#) | |||
Wyodak Coal Mine - 4800083 | — | — | — | — | — | $ | 826 | — | No | — | — | — |
(a) | The types of proceedings by class: (1) Contests of citations and orders – none; (2) contests of proposed penalties – none; (3) complaints for compensation – none; (4) complaints of discharge, discrimination or interference under Section 105 of the Mine Act – none; (5) applications for temporary relief – none; and (6) appeals of judges’ decisions or orders to the FMSHRC – none. |
Document and Entity Information Document and Entity Information - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Jan. 31, 2019 |
Jun. 30, 2018 |
|
Document and Entity Information [Abstract] | |||
Entity Registrant Name | BLACK HILLS CORP /SD/ | ||
Entity Central Index Key | 0001130464 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2018 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Current Fiscal Year End Date | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 60,003,964.507 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 3,239,030,444 |
Consolidated Balance Sheets (Parenthetical) - $ / shares |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Statement of Financial Position [Abstract] | ||
Common Stock, Par Value (usd per share) | $ 1 | $ 1 |
Treasury Stock, Shares | 44,253 | 39,064 |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 |
Common Stock, Shares, Issued | 60,048,567 | 53,579,986 |
Business Description And Significant Accounting Policies: |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Description and Significant Accounting Policies | BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. All of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5. On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21. Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5. Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information. Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12. Cash and Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash. For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash and cash equivalents. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining and Power Generation business segments consists of amounts due from sales of coal, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. Following is a summary of accounts receivable as of December 31 (in thousands):
Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):
(a) Represents allowance balances added with the SourceGas acquisition. Revenue Recognition Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:
The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the year ended December 31, 2018. Sales tax and other similar taxes are excluded from revenues.
The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Black Hills Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Black Hills Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues. Significant Judgments and Estimates TCJA Revenue Reserve The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $37 million during the year ended December 31, 2018. As of December 31, 2018, $19 million has been returned to customers and approximately $18 million remains in reserve as a current regulatory liability. Unbilled Revenue To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed above. We do not typically incur costs that would be capitalized to obtain or fulfill a contract. Practical Expedients Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance. Materials, Supplies and Fuel The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our Natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. Investments We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared. In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of December 31, 2018. The following table presents the carrying value of our investments (in thousands) as of December 31:
Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies. We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands):
Our intangible assets represent easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):
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Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting. Additional information is included in Note 8 and 21. Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. We currently do not have any Level 3 investments. Valuation Methodologies for Derivatives The commodity contracts for the Electric and Gas Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchange-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For over-the-counter swaps and options Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market pricing data. In addition, the fair value for the over-the-counter swaps and option derivatives, if material, include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. Additional information on fair value measurements is included in Notes 10, 11 and 18 . Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980. We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterpart when a legal right of offset exists. Deferred Financing Costs Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. Regulatory Accounting Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material. We had the following regulatory assets and liabilities as of December 31 (in thousands):
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Regulatory assets represent items we expect to recover from customers through probable future rates. Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. The recovery period for these costs is less than a year. Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions. The recovery period for these costs is less than a year. Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2018 are hedged over a maximum forward term of 2 years. Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI, including costs being amortized from the Aquila and SourceGas Transactions. Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown. Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 8 for additional details. Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue. Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills. Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes. Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing. Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs. Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense. Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. Revenue Subject to Refund - Revenue subject to refund at December 31, 2018 represent revenue reserved as a result of the TCJA. See above “TCJA Revenue Reserve” under Revenue recognition for further disclosure. See Note 13 for additional information on regulatory matters. Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. See Notes 13 and 15 for additional information. It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income (Loss). We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. See Note 15 for additional information. Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans. A reconciliation of share amounts used to compute earnings (loss) per share is as follows for the years ended December 31 (in thousands):
The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive for the years ended December 31 (in thousands):
Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. See Note 2 for additional detail on the accounting for the SourceGas Acquisition. Noncontrolling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on Noncontrolling Interests. Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. Recently Issued Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the original guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. We adopted this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we elected the practical expedient which provides for no assessment of these easements. Further, we adopted the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We elected the “package of three” practical expedient. We have implemented a new lease accounting system and adjusted related procedures and controls accordingly. On January 1, 2019, we will record an operating lease right of use asset and an off-setting operating lease obligation liability of approximately $3.2 million. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 1. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the year ended December 31, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Restricted Cash, ASU 2016-18 Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, ASU 2018-02 In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU was issued to address industry concerns regarding the application of current accounting guidance to certain provisions of the new tax reform legislation. This ASU permits entities to make a one-time reclassification from AOCI to retained earnings for stranded tax effects resulting from the newly enacted corporate tax rate. The amount of the reclassification is calculated on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCI. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods therein, and early adoption is permitted. We have implemented this ASU effective December 22, 2017, the enactment date of the TCJA, which resulted in a reclassification of $7.0 million of stranded tax effects from AOCI to retained earnings. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. Improvements to Employee Share-Based Payment Accounting, ASU 2016-09 In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment of $3.2 million to Retained earnings in the Consolidated Balance Sheets as of the date of adoption, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. |
Acquisition: |
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Acquisition | ACQUISITION Acquisition of SourceGas On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumption of $760 million in debt at closing. SourceGas is a 100% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512-mile regulated intrastate natural gas transmission pipeline in Colorado. Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 5.98 million Equity Units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility. In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $45 million for the year ending December 31, 2016. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses on the Consolidated Statements of Income. Our consolidated operating results for the year ended December 31, 2016 include revenues of $348 million and net income of $15 million, attributable to SourceGas for the period from February 12 through December 31, 2016. The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers. We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values. The final purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion, net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million, resulted in goodwill of $940 million. We had up to one year from the acquisition date to finalize the purchase price allocation. The working capital adjustment received in 2016 of $11 million reflected changes in valuation estimates for intangible assets, accrued liabilities and deferred taxes. Approximately $252 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities.
Conditions of SourceGas Acquisition Regulatory Approval The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions. We have met all conditions as set forth in the commissions’ approval orders. Pro Forma Results (unaudited) We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the year ended December 31, 2016. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2016:
We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the year ended December 31, 2016, also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2016, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the year ended December 31, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37%. These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2016, or that may be obtained in the future. Seller’s noncontrolling interest As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with the holder for the 0.5% retained interest. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million. |
Property, Plant And Equipment: |
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Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
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Jointly Owned Facilities: |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Jointly Owned Facilities | JOINTLY OWNED FACILITIES Our consolidated financial statements include our share of several jointly-owned utility and non-regulated facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.
At December 31, 2018, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
Jointly Owned facility - Related Party Colorado Electric owns 50% of the Busch Ranch I Wind Farm while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. On December 11, 2018, Black Hills Electric Generation purchased its 50% ownership interest in the 29 MW Busch Ranch I Wind Farm from AltaGas for $16 million. Colorado Electric retains responsibility for operations of the wind farm. We recorded this purchase as an asset acquisition at fair value with $8.7 million of the purchase price recorded as wind generation assets, and $7.6 million recorded as an intangible asset, reflective of the fair value of the PPA. Black Hills Electric Generation will provide its share of energy from the wind farm to Colorado Electric through a new PPA, which replaces the PPA Colorado Electric had with AltaGas, expiring in October 2037. |
Business Segment Information: |
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Segment Reporting Information, Additional Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Segment Information | BUSINESS SEGMENT INFORMATION Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Segment information was as follows (in thousands):
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Corporate expense reallocation In accordance with GAAP, indirect corporate operating costs previously allocated to BHEP were not reclassified to discontinued operations. These corporate operating costs for 2017 were reallocated to our operating segments; allocated interest was reclassified to Corporate and Other. Indirect corporate operating costs for 2016 were reclassified to Corporate and Other. The reallocation of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 is as follows (in thousands):
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Long-Term Debt: |
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Long-term Debt, Unclassified [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | LONG-TERM DEBT Long-term debt outstanding was as follows (dollars in thousands):
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Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2018. Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by South Dakota Electric and Wyoming Electric are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds. Debt Transactions On December 12, 2018, we paid off the $250 million, 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to pay off this debt. On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt. The issuance of these new senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see Note 12). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate). On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, will now mature on July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated with this term loan is determined based upon our corporate credit rating from S&P, Fitch, and Moody’s for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings and Eurodollar borrowings were 0.000% and 0.700%, respectively, at December 31, 2018. On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan. Amortization Expense Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands):
Dividend Restrictions Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2018, we were in compliance with these covenants. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2018:
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Notes Payable: |
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Notes Payable [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Notes Payable | NOTES PAYABLE Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2018, we were in compliance with all of these financial covenants. We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):
Revolving Credit Facility and CP Program On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively, at December 31, 2018. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2018. Margins and the commitment fee rate decreased in August 2018 due to our upgraded credit rating from S&P. We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net (payments) under the CP Program during 2018 were $(26) million and our notes outstanding as of December 31, 2018 were $186 million. As of December 31, 2018, the weighted average interest rate on CP Program borrowings was 2.88%. As of December 31, 2018 and December 31, 2017, we had outstanding letters of credit totaling approximately $22 million and approximately $27 million, respectively. Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income (Loss). See Note 6 above for additional details. Debt Covenants Under our Revolving Credit Facility and term loan agreements we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter:
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Asset Retirement Obligations: |
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Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS We have identified legal retirement obligations related to reclamation of coal mining sites in the Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment, retirement of gas pipelines at our Gas Utilities and asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment. The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
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We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time. We had identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells. These obligations were classified as held for sale at December 31, 2017. See Note 21. |
Risk Management Activities: |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Risk Management Activities | RISK MANAGEMENT ACTIVITIES Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1. Market Risk Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed to the following market risks, including, but not limited to:
Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified. Our credit exposure at December 31, 2018 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10. Utilities The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements) expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income (Loss). We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from January 2019 through December 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any, is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our hedging position is evaluated at least quarterly. The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of:
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Based on December 31, 2018 prices, a $0.4 million gain would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. Cash Flow Hedges The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2018, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2018, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred.
Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2018, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our Utilities were $6.2 million and $12 million at December 31, 2018 and 2017, respectively. |
Fair Value Measurements: |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances during 2018 or 2017. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. A discussion of fair value of financial instruments is included in Note 11. Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 21. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands):
Fair Value Measures by Balance Sheet Classification As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis, aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions. The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):
Derivatives Offsetting It is our policy to offset in our Consolidated Balance Sheets contracts which provide for legally enforceable netting of our accounts receivable and payable and derivative activities. As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at December 31, 2018 and 2017, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure. Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2018 was as follows (in thousands):
Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2017 were as follows (in thousands):
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Financial Instruments | FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10, were as follows at December 31 (in thousands):
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Cash and Cash Equivalents Included in cash and cash equivalents is cash, money market mutual funds, and term deposits. As part of our cash management process, excess operating cash is invested in money market mutual funds with our bank. Money market mutual funds are not deposits and are not insured by the U.S. Government, the FDIC, or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal. Restricted Cash and Equivalents Restricted cash and cash equivalents represent restricted cash and uninsured term deposits. Notes Payable and Long-Term Debt For additional information on our notes payable and long-term debt, see Note 6 and Note 7. |
Equity: |
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Stockholders' Equity Note [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity | EQUITY Equity Units On November 23, 2015, we issued 5.98 million Equity Units for total gross proceeds of $299 million. Each Equity Unit had a stated amount of $50.00 and consisted of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028. On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued on November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of Black Hills Corporation common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of Black Hills Corporation common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units. See Note 6 for additional information. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds were used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt. At-the-Market Equity Offering Program On August 4, 2017, we renewed the ATM equity offering program, which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2018 and 2017. During the twelve months ended December 31, 2016, we issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million, net of $1.2 million in commissions. Equity Compensation Plans` Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 800,180 shares available to grant at December 31, 2018. Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2018, total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 1.9 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands):
Stock Options The Company has not issued any stock options since 2014 and has 68,749 stock options outstanding at December 31, 2018. The amount of stock options granted during the last three years, and related exercise activity are not material to the Company’s consolidated financial statements. Restricted Stock The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant. The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period. A summary of the status of the restricted stock and restricted stock units at December 31, 2018, was as follows:
The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows:
As of December 31, 2018, there was $8.9 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 years. Performance Share Plan Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.8 million at December 31, 2018 would be reclassified as a liability. Outstanding performance periods at December 31 were as follows (shares in thousands):
A summary of the status of the Performance Share Plan at December 31 was as follows:
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The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:
There were no performance plan payouts during the years ended December 31, 2018, 2017, and 2016. On January 29, 2019, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2016 through December 31, 2018 performance period was at the 74.8 percentile of its peer group and confirmed a payout equal to 161.9% of target shares, valued at $5.7 million. The payout was fully accrued at December 31, 2018. As of December 31, 2018, there was $3.2 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.8 years. Shareholder Dividend Reinvestment and Stock Purchase Plan We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2018, there were 253,418 shares of unissued stock available for future offering under the plan. Preferred Stock Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding. Sale of Noncontrolling Interest in Subsidiary Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes. A partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. Net income available for common stock for the years ended December 31, 2018, 2017 and 2016 was reduced by $14 million, $14 million, and $10 million, respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holders is based on ownership interests with the exception of certain agreed upon adjustments. Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31:
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Regulatory Matters: |
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Regulatory Matters | REGULATORY MATTERS TCJA revenue reserve The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform, was primarily from the change in the federal tax rate from 35% to 21% affecting current income tax expense embedded in those tariffs. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $37 million during the year ended December 31, 2018. As of December 31, 2018, $19 million has been returned to customers. A list of states where benefits to customers of federal tax reform have been approved is summarized below.
In support of returning benefits to customers, the three rate review requests filed in 2017 for Arkansas Gas, Wyoming Gas (Northwest Wyoming) and Rocky Mountain Natural Gas (a pipeline system in Colorado) were adjusted to include the benefits to customers of federal tax reform as discussed below. Excess Deferred Income Taxes As of December 31, 2018 and 2017, we have a regulatory liability associated with TCJA related items of approximately $311 million and $301 million, respectively. The majority of this regulatory liability relates to excess deferred taxes resulting from the remeasurement of deferred tax assets and liabilities in 2017. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $2.1 million of this regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. See Note 15 for more information. Electric Utilities Regulatory Activity Corriedale Wind Project On December 17, 2018, South Dakota Electric and Wyoming Electric filed a joint application with the WPSC for a CPCN to construct a new $57 million, 40 MW wind generation project near Cheyenne, Wyoming. If approved, the 40 MW Corriedale Wind Energy Project would be jointly owned by South Dakota Electric and Wyoming Electric. The project would be largely constructed and placed in service during 2020. Wyoming Electric Integrated Resource Plan On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019. Wyoming Electric Settlement On October 31, 2018, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric will provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulates the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. As of December 31, 2018, we have recorded a liability of $6.0 million related to the PCA. South Dakota Electric Common Use System (CUS) The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2019 the annual revenue requirement increased by $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year. South Dakota Electric Settlement On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a 6-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances as of the settlement date of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously being amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset as of the settlement date of $14 million, previously unamortized, is also being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million. The June 16, 2017 settlement had no impact to base rates. Gas Utilities Regulatory Activity Colorado Gas On October 10, 2018, we received approval from the CPUC for a request to consolidate our Colorado gas utility operations into a new utility entity. The Colorado portion of Black Hills Gas Distribution, LLC, will be combined with Black Hills/Colorado Gas Utility Company, Inc., into a new company named Black Hills Colorado Gas, Inc. The two companies being merged currently serve 187,000 Colorado customers doing business as Black Hills Energy. On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments in safety, reliability and system integrity. Wyoming Gas On November 20, 2018, we received approval from the WPSC for a CPCN to construct a new $54 million, 35-mile natural gas pipeline to enhance supply reliability and delivery capacity for approximately 57,000 customers in central Wyoming. The pipeline, known as the Natural Bridge Pipeline, is planned to be placed in service in late 2019. Arkansas Gas On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new annual revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018. Wyoming Gas On July 16, 2018, the WPSC reached a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. We received the final order in the third quarter of 2018. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018. Kansas Gas On June 19, 2018, Kansas Gas received approval from the Kansas Corporation Commission for an annual increase in revenue of $0.6 million based on inclusion of approximately $8.0 million of eligible capital investments under the Gas System Reliability Rider. The Kansas Legislature passed legislation in 2018 enabling the annual eligible investments to double from approximately $8.0 million to $16 million effective January 1, 2019. RMNG In Colorado, new rates for RMNG went into effect June 1, 2018 after we reached a settlement which was approved by the CPUC. The settlement included $1.1 million in annual revenue increases and an extension of the SSIR to recover costs from 2018 through December 31, 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA. Nebraska Gas On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NPSC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered. On October 2, 2017, Nebraska Gas Distribution filed with the NPSC requesting recovery of $6.8 million, which includes $0.3 million of increased annual revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2018, and went into effect on February 1, 2018. |
Operating Leases: |
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Leases, Operating [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Leases | OPERATING LEASES We have entered into lease agreements for office facilities, communication tower sites, land and equipment. Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands):
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The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):
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Income Taxes: |
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Income Taxes | INCOME TAXES TCJA On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. As a result of the revaluation at December 31, 2017, deferred tax assets and liabilities were reduced by approximately $309 million. Of the $309 million, approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. During the year ended December 31, 2018 we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2018, the Company has amortized $2.1 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. Tax benefit related to legal entity restructuring As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018 and December 31, 2018. As a result of these transactions, additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $73 million were recorded to income tax benefit (expense) on the Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities. Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
Included in discontinued operations is a tax benefit of $2.6 million, $8.4 million and $49 million for 2018, 2017 and 2016, respectively. The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
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The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
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At December 31, 2018, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands):
As of December 31, 2018, we had a $0.4 million valuation allowance against the state NOL carryforwards. Our 2018 analysis of the ability to utilize such NOLs resulted in a $0.4 million increase in the valuation allowance offset by a $1.2 million decrease from expired NOL. This resulted in an increase to tax expense of $0.4 million and a decrease to the state NOL carryforward of $1.2 million. The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2018. This projected decrease impacted the utilization of NOL carryforward in those states where the carryforward period is significantly shorter than the federal carryforward period of 20 years. In certain states, the carryforward period is limited to 5 years. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense. The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.1 million. We recognized no interest expense associated with income taxes for the years ended December 31, 2018, December 31, 2017 and December 31, 2016. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2018 and December 31, 2017. The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which files a separate consolidated tax return from Black Hills Corporation and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. Black Hills Corporation is no longer subject to examination for tax years prior to 2015. We had deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS had challenged our position with respect to the like-kind exchange. In the first quarter of 2016, we reached a settlement agreement in principle with IRS Appeals related to both the like-kind exchange transaction in addition to the R&D credits and deductions issues. In 2016, the settlement resulted in a reduction to the liability for unrecognized tax benefits of approximately $29 million excluding interest. Approximately $17 million of the reduction was to restore accumulated deferred income taxes and the remaining portion of approximately $12 million was reclassified to current taxes payable. As of December 31, 2018, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2019. State tax credits have been generated and are available to offset future state income taxes. At December 31, 2018, we had the following state tax credit carryforwards (in thousands):
As of December 31, 2018, we had an $11 million valuation allowance against the state tax credit carryforwards. Our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $3.5 million of which approximately $1.9 million resulted in an increase to tax expense. The remaining $1.6 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of lower projected apportionment factors resulting in decreased state taxable income in years beyond 2018. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense. |
Other Comprehensive Income: |
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Statement of Comprehensive Income [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Comprehensive Income | OTHER COMPREHENSIVE INCOME We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands):
Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):
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Supplemental Disclosure of Cash flow Information: |
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Supplemental Disclosure of Cash Flow Information | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
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Employee Benefit Plans: |
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Defined Benefit Plan [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Employee Benefit Plans | EMPLOYEE BENEFIT PLANS Defined Contribution Plans We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company. The SourceGas Retirement Savings Plan was merged into the Black Hills Corporation Retirement Savings Plan effective December 31, 2017. The plan design of the Black Hills Corporation 401(k) Plan applies to all eligible employees as of January 1, 2018. Defined Benefit Pension Plan (Pension Plan) We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria. The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments. The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2018, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 29% to 37% return-seeking assets and 63% to 71% liability-hedging assets. Our Pension Plan is funded in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows:
Supplemental Non-qualified Defined Benefit Plans We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company. Plan Assets We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid. Non-pension Defined Benefit Postretirement Healthcare Plans BHC sponsors retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans for participating business units are pre-funded via VEBAs. Pre-65 retirees as well as a grandfathered group of post-65 Cheyenne Light, Fuel and Power (“CLFP”) retirees and a grandfathered group of post-65 former SourceGas employees who retired prior to January 1, 2017 receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible BHC and Black Hills Utility Holdings retirees is provided through an individual market healthcare exchange. Medicare-eligible SourceGas employees who retired after December 31, 2016 also receive retiree medical coverage through an individual market healthcare exchange. Plan Assets We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG Plans provide for partial pre-funding via VEBAs and a Grantor Trust. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Kansas and Iowa. We do not pre-fund the Healthcare Plans for those employees outside Arkansas, Kansas and Iowa. Plan Contributions Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands):
While we do not have required contributions, we expect to make approximately $13 million in contributions to our Pension Plan in 2019. Fair Value Measurements Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):
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Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows: Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is described as a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (ETFs) for diversification into the other sectors of the economy. ETFs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Intermediate-term bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2. AXA Equitable General Fixed Income Fund: This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2. Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2. Common Collective Trust-Real Estate Fund: This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance. Common Collective Trust-Real Estate Fund: This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy. Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. 20% of the shares may be redeemed at the end of each month with a 10-day notice and full redemptions are available at the end of each quarter with 45-day notice, and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI: Benefit Obligations
Employee Benefit Plan Assets
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The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):
Accumulated Benefit Obligation
Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands):
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For the year ended December 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other expense, on the Consolidated Statements of Income. For the years ended December 31, 2017 and 2016, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Consolidated Statements of Income. See Note 1 for additional information. AOCI For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
Assumptions
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The healthcare benefit obligation was determined at December 31 as follows:
Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details. The following benefit payments, which reflect future service, are expected to be paid (in thousands):
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Power Purchase and Transmission Services Agreements Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties:
Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):
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Power Purchase Agreement - Related Party On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in the 29 MW Busch Ranch I Wind Farm, previously owned by AltaGas. Black Hills Electric Generation will provide its 14.5 MW share of energy from the wind farm to Colorado Electric through a new PPA that replaces the PPA that Colorado Electric had with AltaGas, expiring in October 2037. Other Gas Supply Agreements Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044. Purchase Commitments We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract. Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2018, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):
Purchases under these contracts totaled $27 million, $65 million and $31 million for 2018, 2017 and 2016, respectively. The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands):
Future Purchase Agreement - Related Party Wyoming Electric’s PPA for 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on December 31, 2022, includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.1 million per MW which is the equivalent per MW of the pre-construction estimated cost of the Wygen III plant, which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35-year life starting January 1, 2009. The purchase option would be subject to WPSC and FERC approval in order to obtain regulatory treatment. Power Sales Agreements Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:
Related Party Lease Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations. Reimbursement Agreement We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. Environmental Matters We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies. Solid Waste Disposal Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date. In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date. Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. Reclamation Liability For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under its land lease for Busch Ranch I, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. See Note 8 for additional information. Manufactured Gas Processing As a result of the Aquila Transaction, we acquired whole and partial liabilities for former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.1 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.0 million regulatory asset for manufactured gas processing sites; see Note 1. As of December 31, 2018, our estimated liabilities for Iowa’s MGP site currently range from approximately $2.6 million to $6.1 million for which we had $2.6 million accrued for remediation of the site as of December 31, 2018 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties. For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K. Legal Proceedings In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements. In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities. |
Guarantees: |
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Guarantees [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||
Guarantees | GUARANTEES We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee. We had the following guarantees in place as of (in thousands):
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Discontinued Operations: |
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Discontinued Operations | DISCONTINUED OPERATIONS Results of operations for discontinued operations have been classified as Net (loss) from discontinued operations in the accompanying Consolidated Statements of Income. Current assets and current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Consolidated Balance Sheets as “Current assets held for sale” and “Current liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our consolidated financial statements. Oil and Gas Segment On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of December 31, 2018, we have sold our oil and gas properties and completed the exit of the Oil and Gas business. In 2017, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale were reasonable based on the information that was known when the estimates were made. At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million. There were no adjustments made to the fair value of our held for sale liabilities. For the year ended December 31, 2018, we recorded $3.3 million of expenses comprised of royalty payments and reclamation costs related to final closing on the sale of BHEP assets. Total assets and liabilities of BHEP at December 31, 2017 were classified as Current assets held for sale and Current liabilities held for sale on the accompanying Consolidated Balance Sheets due to the final disposals occurring in 2018.
At December 31, 2017, the Oil and Gas segment’s net deferred tax assets were primarily comprised of basis differences on oil and gas properties. BHEP’s Other current liabilities at December 31, 2017 consisted primarily of accrued royalties, payroll and property taxes. Other noncurrent liabilities at December 31, 2017 consisted primarily of ARO obligations relating to plugging and abandonment of oil and gas wells. Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands):
Full Cost Accounting Historically, we used the full cost method of accounting for oil and gas production activities. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. Impairment of long-lived assets As discussed above, at December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required a write down of $20 million. There were no adjustments made to the fair value of our held for sale liabilities. As a result of continued low commodity prices throughout 2016, we recorded non-cash ceiling test impairments of our Oil and Gas assets totaling approximately $92 million for the year ended December 31, 2016. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead; for crude oil, the average NYMEX price was $42.75 per barrel, adjusted to $37.35 per barrel at the wellhead. During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million, in addition to the ceiling test impairments noted above. |
Oil and Gas Reserves (Unaudited): |
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Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil and Gas Reserves (Unaudited) | OIL AND GAS RESERVES (Unaudited) On November 1, 2017, we initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. On November 1, 2017, we stopped the use of the full-cost method of accounting for our oil and gas business. The assets and liabilities have been classified as held for sale and the results of operations are included in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As a result, our oil and gas reserves were no longer considered significant in 2017. Oil and Gas reserves were considered significant in 2016. For more information, see Note 21. Costs Incurred Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
Reserves The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and a reconciliation of the changes. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 31 years of practical experience in petroleum engineering and over 29 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
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Capitalized Costs Following is information concerning capitalized costs for the years ended December 31 (in thousands):
Results of Operations For more on oil and gas producing activities included in discontinued operations, see Note 21. Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
Unproved Properties Unproved properties not subject to amortization at December 31, 2016 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.9 million of interest during 2016 on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands):
Standardized Measure of Discounted Future Net Cash Flows Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands):
The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):
Changes in the standardized measure from “revisions of previous quantity estimates” were driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications were generally made at the well level each year through the reserve review process. These production profile modifications were based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments were reviewed each year and were often modified in response to current market conditions for items such as permitting and service availability. |
Quarterly Historical Data (Unaudited): |
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Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarterly Historical Data (Unaudited) | QUARTERLY HISTORICAL DATA (Unaudited) The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2018 and 2017.
Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million, respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring.
Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter. Included within the Income (loss) from continuing operations in the fourth quarter of 2017 is a net tax benefit of $7.6 million from the impact of the TCJA, as well as a tax benefit of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition. Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13 million. |
Business Description (Policies) |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Description | Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. All of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5. On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21. |
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Use of Estimates and Basis of Presentation | Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. |
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Principles of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5. Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information. |
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Variable Interest Entities | Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12. |
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Cash and Cash Equivalents and Restricted Cash | Cash and Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash. For purposes of the cash flow statements, we consider all highly liquid investments with original maturities of three months or less at the time of purchase to be cash and cash equivalents. |
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Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining and Power Generation business segments consists of amounts due from sales of coal, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. |
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Revenue Recognition | Revenue Recognition Revenue is recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:
The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the year ended December 31, 2018. Sales tax and other similar taxes are excluded from revenues.
The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 840, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. The majority of our lease revenue is related to a 20-year power sale agreement between Black Hills Colorado IPP and affiliate Colorado Electric. This agreement is accounted for as a direct financing lease whereby Black Hills Colorado IPP receives revenue for energy delivered and related capacity payments. This lease revenue is eliminated in our consolidated revenues. Significant Judgments and Estimates TCJA Revenue Reserve The TCJA or “tax reform” signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions in the states in which it provides utility service to deliver to customers the benefits of a lower corporate federal income tax rate beginning in 2018 with the passage of the TCJA. We have received state utility commission approvals to provide the benefits of federal tax reform to utility customers in six states. We estimated and recorded a reserve to revenue of approximately $37 million during the year ended December 31, 2018. As of December 31, 2018, $19 million has been returned to customers and approximately $18 million remains in reserve as a current regulatory liability. Unbilled Revenue To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed above. We do not typically incur costs that would be capitalized to obtain or fulfill a contract. Practical Expedients Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance. |
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Materials, Supplies and Fuel | Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our Natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. |
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Investments | Investments We account for investments that we do not control under the cost method of accounting as we do not have the ability to exercise significant influence over the operating and financial policies of the investee. The cost method investments are recorded at cost and we record dividend income when applicable dividends are declared. In February 2018, we contributed $28 million of assets in exchange for equity securities in a privately held company. The carrying value of our investment in the equity securities was determined using the cost method. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. We estimate that the fair value of this cost method investment approximated or exceeded its carrying value as of December 31, 2018. |
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Property, Plant and Equipment | Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. |
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Goodwill and Intangible Assets | Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies. |
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Asset Retirement Obligations | Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting. |
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Fair Value Measurements | Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. We currently do not have any Level 3 investments. |
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Derivatives and Hedging Activities | Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980. We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterpart when a legal right of offset exists. |
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Deferred Financing Costs | Deferred Financing Costs Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. |
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Regulatory Accounting | Regulatory Accounting Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material. We had the following regulatory assets and liabilities as of December 31 (in thousands):
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Regulatory assets represent items we expect to recover from customers through probable future rates. Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. The recovery period for these costs is less than a year. Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions. The recovery period for these costs is less than a year. Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2018 are hedged over a maximum forward term of 2 years. Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI, including costs being amortized from the Aquila and SourceGas Transactions. Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown. Asset Retirement Obligations - Asset retirement obligations represent the estimated recoverable costs for legal obligations associated with the retirement of a tangible long-lived asset. See Note 8 for additional details. Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue. Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills. Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes. Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing. Gas Supply Contract Termination - Black Hills Gas Holdings had agreements under the previous ownership that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Nebraska, Colorado, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the NPSC, CPUC and WPSC, on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years. We terminated the contract and settled the liability on April 29, 2016. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs. Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense. Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. Revenue Subject to Refund - Revenue subject to refund at December 31, 2018 represent revenue reserved as a result of the TCJA. See above “TCJA Revenue Reserve” under Revenue recognition for further disclosure. |
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Income Taxes | Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21%. See Notes 13 and 15 for additional information. It is our policy to apply the flow-through method of accounting for investment tax credits. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income (Loss). We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets. |
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Earnings per Share of Common Stock | Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans. |
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Business Combinations | Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates. |
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Noncontrolling Interest | Noncontrolling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. |
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Share-Based Compensation | Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. |
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Recently Issued and Adopted Accounting Standards | Recently Issued Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for most leases, whereas today only financing-type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement, which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Under the original guidance, lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard. The FASB also issued additional amendments to the new lease standard in July 2018, ASU No. 2018-11, allowing companies to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. We adopted this standard on January 1, 2019. For existing or expired land easements that were not previously accounted for as a lease, we elected the practical expedient which provides for no assessment of these easements. Further, we adopted the new standard with a cumulative effect adjustment with prior year comparative financial information remaining as previously reported when transitioning to the new standard. The standard also provides a transition practical expedient, commonly referred to as the “package of three”, that must be taken together and allows entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. We elected the “package of three” practical expedient. We have implemented a new lease accounting system and adjusted related procedures and controls accordingly. On January 1, 2019, we will record an operating lease right of use asset and an off-setting operating lease obligation liability of approximately $3.2 million. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 1. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires employers to report the service cost component in the same line item(s) as other compensation costs, and requires the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis for the year ended December 31, 2018. Retrospective impact was not material and therefore prior year presentation was not changed. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 Effective January 1, 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows. Statement of Cash Flows: Restricted Cash, ASU 2016-18 Effective January 1, 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU provides guidance on the presentation of restricted cash or restricted cash equivalents and reduces the diversity in practice. This ASU requires amounts generally described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period total amounts on the statement of cash flows. We elected, as permitted by the standard, to early adopt ASU 2016-18 retrospectively as of January 1, 2017 and have applied it to all periods presented herein. The adoption of ASU 2016-18 did not have a material impact to our condensed consolidated financial statements. The effect of the adoption of ASU 2016-18 on our Condensed Consolidated Statements of Cash Flows was to include restricted cash balances in the beginning and end of period balances of cash, cash equivalents, and restricted cash. The change in restricted cash was previously disclosed in investing activities in the Condensed Consolidated Statements of Cash Flows. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, ASU 2018-02 In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU was issued to address industry concerns regarding the application of current accounting guidance to certain provisions of the new tax reform legislation. This ASU permits entities to make a one-time reclassification from AOCI to retained earnings for stranded tax effects resulting from the newly enacted corporate tax rate. The amount of the reclassification is calculated on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCI. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods therein, and early adoption is permitted. We have implemented this ASU effective December 22, 2017, the enactment date of the TCJA, which resulted in a reclassification of $7.0 million of stranded tax effects from AOCI to retained earnings. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. Improvements to Employee Share-Based Payment Accounting, ASU 2016-09 In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment of $3.2 million to Retained earnings in the Consolidated Balance Sheets as of the date of adoption, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. |
Business Description (Tables) |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Receivable and Allowance for Doubtful Accounts | Following is a summary of accounts receivable as of December 31 (in thousands):
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Schedule of Valuation and Qualifying Accounts Disclosure | Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):
(a) Represents allowance balances added with the SourceGas acquisition. |
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Disaggregation of Revenue | The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the year ended December 31, 2018. Sales tax and other similar taxes are excluded from revenues.
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Materials, Supplies and Fuel | The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
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Investments | The following table presents the carrying value of our investments (in thousands) as of December 31:
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Schedule of Accrued Liabilities | The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):
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Goodwill | Goodwill balances were as follows (in thousands):
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Intangible Assets | Changes to intangible assets for the years ended December 31, were as follows (in thousands):
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Regulatory Assets and Liabilities | We had the following regulatory assets and liabilities as of December 31 (in thousands):
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Earnings Per Share of Common Stock | A reconciliation of share amounts used to compute earnings (loss) per share is as follows for the years ended December 31 (in thousands):
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Antidilutive Securities | The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive for the years ended December 31 (in thousands):
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Acquisition (Tables) |
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Final Purchase Price Allocation of Fair Value of Assets Acquired and Liabilities Assumed |
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Schedule of Pro Forma Results | The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2016:
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Property, Plant and Equipment (Tables) |
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Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment | Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
_____________
_____________
___________
___________
|
Jointly Owned Facilities (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Jointly Owned Utility Plants | At December 31, 2018, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
|
Business Segment Information (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting Information, Additional Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment information included in Consolidated Balance Sheets | Segment information was as follows (in thousands):
__________________
_________________
_______________
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Segment information included in Consolidated Statements of Income |
________________
________________
________________
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Disposal Groups, Including Discontinued Operations | The reallocation of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 is as follows (in thousands):
________________________
|
Long-Term Debt (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt, Unclassified [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Long-term Debt Instruments | Long-term debt outstanding was as follows (dollars in thousands):
_______________
|
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Schedule of Maturities of Long-term Debt | Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
|
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Deferred Financing Costs | Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands):
|
Notes Payable (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | ||||||||||||||||||||||||||||||||||||
Notes Payable [Abstract] | ||||||||||||||||||||||||||||||||||||
Schedule of Short-term Debt | We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands):
|
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Schedule of Credit Facility Covenants | Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter:
|
Asset Retirement Obligations (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Change in Asset Retirement Obligation | The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands):
_____________________
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Risk Management Activities (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Contract or notional amounts and terms of marketing activities and derivative commodity instruments | The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of:
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Derivative Instruments, Gain (Loss) | The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2018, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2018, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred.
Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2018, 2017 and 2016 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
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Fair Value Measurements (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands):
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Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):
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Schedule of Derivative Offsetting on Balance Sheet | Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2018 was as follows (in thousands):
Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2017 were as follows (in thousands):
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Fair Value of Financial Instruments (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of financial instruments | The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10, were as follows at December 31 (in thousands):
_______________
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Equity (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stockholders' Equity Note [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs | Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands):
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Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Variable Interest Entities | We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31:
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Restricted Stock | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | A summary of the status of the restricted stock and restricted stock units at December 31, 2018, was as follows:
The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows:
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Performance Shares | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | Outstanding performance periods at December 31 were as follows (shares in thousands):
A summary of the status of the Performance Share Plan at December 31 was as follows:
_____________________
The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:
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Regulatory Matters (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||
Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||
Schedule of TCJA (Federal Tax Reform) Benefits Passed On To Customers By State | A list of states where benefits to customers of federal tax reform have been approved is summarized below.
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Operating Leases (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||
Leases, Operating [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||
Operating Leases of Lessor Disclosure | Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands):
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Schedule of Future Minimum Rental Payments for Operating Leases | The following is a schedule of future minimum payments required under the operating lease agreements (in thousands):
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Income Taxes (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
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Schedule of Deferred Tax Assets and Liabilities | The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
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Schedule of Effective Income Tax Rate Reconciliation | The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
_________________________
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Summary of Operating Loss Carryforwards | At December 31, 2018, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands):
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Summary of Income Tax Contingencies | The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):
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State and Local Jurisdiction | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Loss Carryforwards [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of State Tax Carryforwards | State tax credits have been generated and are available to offset future state income taxes. At December 31, 2018, we had the following state tax credit carryforwards (in thousands):
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Other Comprehensive Income (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Statement of Comprehensive Income [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassification out of Accumulated Other Comprehensive Income | The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands):
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Schedule of Accumulated Other Comprehensive Income (Loss) | Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):
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Supplemental Cash Flow Information (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Cash Flow Information [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Disclosure of Cash Flow Information |
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Employee Benefit Plans (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Allocation of Plan Assets | The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows:
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Schedule of Defined Contribution Plans Contributions | Contributions for the years ended December 31 were as follows (in thousands):
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Schedule of Changes in Projected Benefit Obligations | The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI: Benefit Obligations
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Schedule of Changes in Fair Value of Plan Assets |
____________________
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Schedule of Amounts Recognized in Balance Sheet | The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):
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Schedule of Accumulated and Projected Benefit Obligations | Accumulated Benefit Obligation
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Components of net periodic benefit cost | Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands):
____________________
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Schedule of Net Periodic Benefit Cost Not yet Recognized | For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands):
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Schedule of Assumptions Used | Assumptions
_____________________________
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Schedule of Health Care Cost Trend Rates | The healthcare benefit obligation was determined at December 31 as follows:
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Schedule of Expected Benefit Payments | The following benefit payments, which reflect future service, are expected to be paid (in thousands):
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Pension Plans, Defined Benefit | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Allocation of Plan Assets | The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands):
_____________
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Postretirement Health Coverage | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Allocation of Plan Assets |
_____________
|
Commitments and Contingencies (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Purchase Commitment [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecorded Unconditional Purchase Obligations Disclosure | The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands):
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Power purchased | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Purchase Commitment [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Purchase Commitment | Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):
________________
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Purchased Gas Cost Obligation | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Purchase Commitment [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Purchase Commitment | At December 31, 2018, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):
|
Guarantees (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||
Guarantees [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Guarantor Obligations | We had the following guarantees in place as of (in thousands):
_______________________
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Discontinued Operations (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Discontinued Operations and Disposal Groups [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Disposal Groups, Including Discontinued Operations, Balance Sheet Accounts | Total assets and liabilities of BHEP at December 31, 2017 were classified as Current assets held for sale and Current liabilities held for sale on the accompanying Consolidated Balance Sheets due to the final disposals occurring in 2018.
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Disposal Groups, Including Discontinued Operations, Income Statement | Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands):
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Oil and Gas Exploration and Production Industries Disclosure (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure | Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands):
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Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and a reconciliation of the changes. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 31 years of practical experience in petroleum engineering and over 29 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding.
________________________
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Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure | Following is information concerning capitalized costs for the years ended December 31 (in thousands):
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Results of Operations for Oil and Gas Producing Activities Disclosure | Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands):
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Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization | The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands):
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Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands):
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Changes In Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserve Disclosures | The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):
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Quarterly Historical Data (Unaudited) (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Quarterly Financial Information | The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2018 and 2017.
Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million, respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring.
Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter. Included within the Income (loss) from continuing operations in the fourth quarter of 2017 is a net tax benefit of $7.6 million from the impact of the TCJA, as well as a tax benefit of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition. Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13 million. |
Business Description And Significant Accounting Policies: Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | ||||
Balance at Beginning of Year | $ 3,209 | $ 3,081 | $ 2,392 | $ 1,741 |
Adjustments | 0 | 0 | 2,158 | |
Additions Charged to Costs and Expenses | 6,859 | 4,926 | 2,704 | |
Recoveries and Other Additions | 4,092 | 8,262 | 4,915 | |
Write-offs and Other Deductions | (10,823) | (12,499) | (9,126) | |
Balance at End of Year | $ 3,209 | $ 3,081 | $ 2,392 |
Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Materials and supplies | $ 75,081 | $ 69,732 |
Fuel - Electric Utilities | 2,850 | 2,962 |
Natural gas in storage | 39,368 | 40,589 |
Total materials, supplies and fuel | $ 117,299 | $ 113,283 |
Business Description And Significant Accounting Policies: Investments (Details) - USD ($) $ in Thousands |
Feb. 28, 2018 |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|---|
Investment [Line Items] | |||
Investments | $ 41,013 | $ 13,090 | |
Cost-method Investments | |||
Investment [Line Items] | |||
Assets Held for Sale Used to Acquire Other Investments | $ 28,000 | ||
Investments | 28,201 | 0 | |
Cash Surrender Value | |||
Investment [Line Items] | |||
Investments | $ 12,812 | $ 13,090 |
Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Accrued employee compensation, benefits and withholdings | $ 63,742 | $ 52,467 |
Accrued property taxes | 42,510 | 42,029 |
Customer Deposits and Prepayments | 43,574 | 44,420 |
Accrued interest | 31,759 | 33,822 |
Contributions in Aid of Construction | 1,485 | 1,552 |
Other (none of which is individually significant) | 32,431 | 45,172 |
Total accrued liabilities | $ 215,501 | $ 219,462 |
Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | $ 1,299,454 | $ 1,299,454 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | 1,299,454 | 1,299,454 |
Electric Utilities | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 248,479 | 248,479 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | 248,479 | 248,479 |
Gas Utilities | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 1,042,210 | 1,042,210 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | 1,042,210 | 1,042,210 |
Power Generation | ||
Goodwill [Roll Forward] | ||
Goodwill, Beginning Balance | 8,765 | 8,765 |
Goodwill | 0 | 0 |
Goodwill, Ending Balance | $ 8,765 | $ 8,765 |
Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 |
Sep. 30, 2018 |
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||
Net Income (Loss) Available to Common Stockholders, Basic | $ 86,571 | $ 16,950 | $ 21,917 | $ 133,004 | $ 50,653 | $ 27,663 | $ 22,195 | $ 76,523 | $ 258,442 | $ 177,034 | $ 72,970 |
Weighted average shares - Basic (in shares) | 54,420 | 53,221 | 51,922 | ||||||||
Dilutive effect of: | |||||||||||
Equity Units (in shares) | 898 | 1,783 | 1,222 | ||||||||
Equity compensation (in shares) | 168 | 116 | 127 | ||||||||
Weighted average shares - diluted (in shares) | 55,486 | 55,120 | 53,271 | ||||||||
Total earnings (loss) per share of common stock, Diluted (usd per share) | $ 1.49 | $ 0.31 | $ 0.40 | $ 2.46 | $ 0.92 | $ 0.50 | $ 0.40 | $ 1.39 | $ 4.66 | $ 3.21 | $ 1.37 |
Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 16 | 11 | 3 |
Equity Compensation | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share | |||
Outstanding securities not included in the computation of diluted earnings per share (in shares) | 16 | 11 | 3 |
Business Description And Significant Accounting Policies: Leases (Details) - Subsequent Event $ in Millions |
Jan. 01, 2019
USD ($)
|
---|---|
Subsequent Event [Line Items] | |
Operating Lease, Right-of-Use Asset | $ 3.2 |
Operating Lease, Liability | $ 3.2 |
Business Description And Significant Accounting Policies: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 22, 2017 |
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Retained Earnings | Accounting Standards Update 2018-02 | |||
Reclassification of certain tax effects from AOCI | $ 7,000 | ||
Accumulated Other Comprehensive Income (Loss) | |||
Reclassification of certain tax effects from AOCI | $ 740 | $ (7,000) | |
Accumulated Other Comprehensive Income (Loss) | Accounting Standards Update 2018-02 | |||
Reclassification of certain tax effects from AOCI | $ (7,000) |
Business Description And Significant Accounting Policies: Improvement To Employee Share-Based Payment Accounting (Details) $ in Thousands |
12 Months Ended |
---|---|
Dec. 31, 2017
USD ($)
| |
Retained Earnings Adjustments [Line Items] | |
Tax effect of share-based compensation | $ 3,717 |
Retained Earnings | Accounting Standards Update 2016-09 | |
Retained Earnings Adjustments [Line Items] | |
Tax effect of share-based compensation | $ 3,184 |
Business Segment Information: Segment Assets (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 6,963,327 | $ 6,658,902 |
Discontinued Operations, Held-for-sale | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 0 | 84,242 |
Corporate, Non-Segment | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 209,478 | 115,612 |
Electric Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 2,895,577 | 2,906,275 |
Gas Utilities | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 3,623,475 | 3,426,466 |
Power Generation | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | 154,203 | 60,852 |
Mining | ||
Segment Reporting, Asset Reconciling Item | ||
Total Assets | $ 80,594 | $ 65,455 |
Business Segment Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | $ 6,000,015 | $ 5,567,518 |
Corporate, Non-Segment | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 22,269 | 11,954 |
Electric Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 3,109,772 | 2,990,208 |
Gas Utilities | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 2,506,531 | 2,251,193 |
Power Generation | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | 185,793 | 155,793 |
Mining | ||
Segment Reporting Information [Line Items] | ||
Property, plant and equipment | $ 175,650 | $ 158,370 |
Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Long-term Debt, Unclassified [Abstract] | ||
2019 | $ 5,743 | $ 5,743 |
2020 | 505,743 | |
2021 | 8,435 | |
2022 | 0 | |
2023 | 525,000 | |
Thereafter | $ 1,937,855 |
Long-Term Debt: Amortization Expense (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Long-term Debt, Unclassified [Abstract] | |||
Deferred Finance Costs Remaining, Noncurrent | $ 20,990 | ||
Amortization expense for deferred financing costs | $ 2,829 | $ 3,349 | $ 3,861 |
Long-Term Debt: Dividend Restrictions (Details) $ in Millions |
Dec. 31, 2018
USD ($)
|
---|---|
Utilities Group | |
Debt Instrument [Line Items] | |
Restricted Net Assets for Subsidiaries | $ 257 |
Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory assets | $ 284,235 | $ 297,454 | |
Deferred Derivative Gain (Loss) | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory assets | 6,200 | 12,000 | |
Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 1,101 | (2,207) | $ 890 |
Net (loss) from Discontinued Operations | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | (50) |
Fuel, purchased power and cost of natural gas sold | Not Designated as Hedging Instrument | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivative, Gain (Loss) on Derivative, Net | $ 1,101 | $ (2,207) | $ 940 |
Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents - carrying amount | $ 20,776 | $ 15,420 |
Restricted cash - carrying amount | 3,369 | 2,820 |
Notes payable | 185,620 | 211,300 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and cash equivalents - carrying amount | 20,776 | 15,420 |
Restricted cash - carrying amount | 3,369 | 2,820 |
Notes payable | 185,620 | 211,300 |
Long-term debt, including current maturities - carrying amount | 2,956,578 | 3,115,143 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Cash and Cash Equivalents, Fair Value Disclosure | 20,776 | 15,420 |
Restricted Cash Fair Value Disclosure | 3,369 | 2,820 |
Notes payable - fair value | 185,620 | 211,300 |
Long-term debt, including current maturities - fair value | $ 3,039,108 | $ 3,350,544 |
Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Aug. 04, 2017 |
Jun. 30, 2016 |
|
At The Market Equity Offering Program Authorized Aggregate Value | $ 300.0 | $ 200.0 | |
Common Stock | |||
At The Market Equity Offering Program Shares Issued | 1,968,738 | ||
At The Market Equity Program Proceeds from Sale of Stock | $ 119.0 | ||
Payments of Stock Issuance Costs | $ 1.2 |
Equity: Equity Compensation Plans (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Stockholders' Equity Note [Abstract] | |||
Shares available for grant | 800,180 | ||
Unrecognized compensation expense | $ 12,000 | ||
Weighted-average recognition period | 1 year 11 months | ||
Stock-based compensation expense | $ 12,390 | $ 7,626 | $ 10,885 |
Equity: Stock Options (Details) |
Dec. 31, 2018
shares
|
---|---|
Employee Stock Option | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Shares exercisable at end of period | 68,749 |
Equity: Dividend Reinvestment and Stock Purchase Plan (Details) |
Dec. 31, 2018
shares
|
---|---|
Class of Stock [Line Items] | |
Unissued Shares Available | 253,418 |
Dividend Reinvestment Plan | |
Class of Stock [Line Items] | |
Percent of recent average market price | 100.00% |
Equity: Preferred Stock (Details) |
Dec. 31, 2018
shares
|
---|---|
Stockholders' Equity Note [Abstract] | |
Preferred Stock, Shares Authorized | 25,000,000 |
Preferred Stock, Shares Outstanding | 0 |
Equity: Noncontrolling Interest in Subsidiary (Details) $ in Thousands |
3 Months Ended | 12 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Apr. 14, 2016
USD ($)
|
Dec. 31, 2018
USD ($)
|
Sep. 30, 2018
USD ($)
|
Jun. 30, 2018
USD ($)
|
Mar. 31, 2018
USD ($)
|
Dec. 31, 2017
USD ($)
|
Sep. 30, 2017
USD ($)
|
Jun. 30, 2017
USD ($)
|
Mar. 31, 2017
USD ($)
|
Dec. 31, 2018
USD ($)
MW
|
Dec. 31, 2017
USD ($)
|
Dec. 31, 2016
USD ($)
|
|
Electric Generation Capacity, Megawatts | MW | 200 | |||||||||||
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage | 49.90% | |||||||||||
Proceeds from Noncontrolling Interests | $ 216,000 | $ 0 | $ 0 | $ 216,370 | ||||||||
Number of Days the Company has to Pay Distributions of Net Income Attributable to Noncontrolling Interests | 30 days | |||||||||||
Net income attributable to noncontrolling interest | $ (3,773) | $ (3,994) | $ (2,823) | $ (3,630) | $ (3,568) | $ (3,935) | $ (3,116) | $ (3,623) | $ (14,220) | (14,242) | (9,661) | |
Power Generation | ||||||||||||
Net income attributable to noncontrolling interest | (14,220) | (14,135) | $ (9,559) | |||||||||
Current assets | ||||||||||||
Assets | 13,620 | 14,837 | 13,620 | 14,837 | ||||||||
Property, plant and equipment of variable interest entities, net | ||||||||||||
Assets | 199,839 | 208,595 | 199,839 | 208,595 | ||||||||
Current liabilities | ||||||||||||
Liabilities | $ 5,174 | $ 4,565 | $ 5,174 | $ 4,565 |
Regulatory Matters: Excess Deferred Income Taxes (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 309.0 | |
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 19.0 | |
Deferred Income Tax Charge | ||
Tax Cuts and Jobs Act of 2017, Provisional Income Tax Expense (Benefit) | 311.0 | |
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 301.0 | |
Revenue Subject to Refund | ||
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 2.1 |
Operating Leases (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Operating Leases, Rent Expense, Net [Abstract] | |||
Rent expense | $ 2,667 | $ 10,325 | $ 9,568 |
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | |||
2019 | 1,052 | ||
2020 | 464 | ||
2021 | 344 | ||
2022 | 224 | ||
2023 | 216 | ||
Thereafter | $ 1,776 |
Income Taxes: Tax Cut and Jobs Act (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 309,000 | ||
Increase (Decrease) in Regulatory Liabilities | $ 18,533 | (4,536) | $ (14,082) |
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | 19,000 | ||
Deferred Income Tax Charge | |||
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit) | $ 301,000 | ||
Increase (Decrease) in Regulatory Liabilities | 11,000 | ||
Revenue Subject to Refund | |||
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits | $ 2,100 |
Income Taxes: Tax Benefit Related to Legal Restructuring (Details) - USD ($) $ in Thousands |
3 Months Ended | 12 Months Ended | |||
---|---|---|---|---|---|
Dec. 31, 2018 |
Mar. 31, 2018 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Deferred Income Tax Expense (Benefit) | $ (24,239) | $ 80,992 | $ 82,704 | ||
Other Restructuring | |||||
Deferred Tax Assets, Goodwill and Intangible Assets | $ 73,000 | 73,000 | |||
Deferred Income Tax Expense (Benefit) | $ 23,000 | $ 49,000 | $ 73,000 |
Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Current: | |||
Federal | $ 325 | $ (6,193) | $ (21,806) |
State | 247 | (1,432) | (1,797) |
Total Current | 572 | (7,625) | (23,603) |
Deferred: | |||
Federal | (23,295) | 76,567 | 78,997 |
State | 815 | 4,470 | 3,759 |
Excess Deferred Amortization | (1,727) | 0 | 0 |
Tax credit amortization | (32) | (45) | (52) |
Total Deferred | (24,239) | 80,992 | 82,704 |
Total Current and Deferred | (23,667) | 73,367 | 59,101 |
Discontinued Operation, Tax Effect of Discontinued Operation | $ (2,618) | $ (8,413) | $ (48,626) |
Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Deferred Tax Assets, Net [Abstract] | ||
Regulatory liabilities | $ 92,966 | $ 90,742 |
Employee benefits | 14,039 | 18,724 |
Federal net operating loss | 139,371 | 155,276 |
Other deferred tax assets | 101,579 | 74,561 |
Less: Valuation allowance | (11,809) | (9,121) |
Total deferred tax assets | 336,146 | 330,182 |
Deferred tax liabilities: | ||
Accelerated depreciation, amortization and other plant-related differences | (529,338) | (510,774) |
Regulatory assets | (32,324) | (26,245) |
Goodwill | (602) | (46,392) |
State deferred tax liability | (64,095) | (58,930) |
Deferred costs | (13,351) | (16,063) |
Other deferred tax liabilities | (7,767) | (8,298) |
Total deferred tax liabilities | (647,477) | (666,702) |
Net deferred tax liability | $ 311,331 | $ 336,520 |
Income Taxes: Net Operating Loss Carryforwards (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Operating Loss Carryforwards [Line Items] | |||
Deferred Income Tax Expense (Benefit) | $ (24,239) | $ 80,992 | $ 82,704 |
Deferred Tax Assets, Operating Loss Carryforwards | 139,371 | $ 155,276 | |
Internal Revenue Service (IRS) | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 663,741 | ||
State and Local Jurisdiction | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards | 542,632 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 3,500 | ||
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards | |||
Operating Loss Carryforwards [Line Items] | |||
Operating Loss Carryforwards Valuation Allowance | 400 | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 400 | ||
Valuation Allowance Reduction due to Expired NOL | 1,200 | ||
Deferred Income Tax Expense (Benefit) | 400 | ||
Deferred Tax Assets, Operating Loss Carryforwards | $ 1,200 |
Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Liability for Uncertain Tax Positions, Noncurrent, Period Start | $ 3,263 | $ 3,592 | $ 31,986 |
Additions for prior year tax positions | 251 | 358 | 2,423 |
Reductions for prior year tax positions | (417) | (5,713) | (19,174) |
Additions for current year tax positions | 486 | 5,026 | 0 |
Settlements | 0 | 0 | (11,643) |
Liability for Uncertain Tax Positions, Noncurrent, Period End | 3,583 | $ 3,263 | $ 3,592 |
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | $ 100 |
Income Taxes: Interest, Penalties and Audits (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Income Tax Examination [Line Items] | |||
Deferred Income Tax Expense (Benefit) | $ (24,239,000) | $ 80,992,000 | $ 82,704,000 |
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 0 | 0 | $ 11,643,000 |
Unrecognized Tax Benefits, Interest Expense | 0 | 0 | |
Unrecognized Tax Benefits, Interest Accrued | 0 | $ 0 | |
Like-Kind Exchange, Aquila and IPP Transactions | |||
Income Tax Examination [Line Items] | |||
Deferred Income Tax Expense (Benefit) | 125,000,000 | ||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 29,000,000 | ||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities - Reducing Accumulated Deferred Income Taxes | 17,000,000 | ||
Unrecognized Tax Benefits, Decrease From Settlements With Taxing Authorities - Reclassified to Current Taxes Payable | $ 12,000,000 |
Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Non-cash investing activities and financing from continuing operations - | |||
Property, plant and equipment acquired with accrued liabilities | $ 69,017 | $ 28,191 | $ 27,034 |
Increase (decrease) in capitalized assets associated with asset retirement obligations | 2,625 | 3,198 | 8,577 |
Cash (paid) refunded during the period for continuing operations- | |||
Interest (net of amount capitalized) | (137,965) | (132,428) | (113,627) |
Income taxes (paid) refunded | $ (14,730) | $ 1,775 | $ (1,156) |
Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands |
Dec. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Pension Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | $ 428,851 | $ 450,394 |
Supplemental Employee Retirement Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | 40,530 | 41,243 |
Other Postretirement Benefit Plans, Defined Benefit | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Accumulated Benefit Obligation | $ 60,817 | $ 69,339 |
Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands |
Dec. 31, 2018
USD ($)
|
---|---|
Pension Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2019 | $ 24,405 |
2020 | 25,847 |
2021 | 26,951 |
2022 | 27,972 |
2023 | 29,002 |
2024-2028 | 151,915 |
Supplemental Employee Retirement Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2019 | 1,463 |
2020 | 1,406 |
2021 | 1,617 |
2022 | 1,727 |
2023 | 1,912 |
2024-2028 | 12,208 |
Other Postretirement Benefit Plans, Defined Benefit | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2019 | 4,898 |
2020 | 5,545 |
2021 | 5,695 |
2022 | 5,849 |
2023 | 5,607 |
2024-2028 | $ 24,953 |
Commitments And Contingencies: Power Purchase Agreement - Related Party (Details) - MW |
12 Months Ended | |
---|---|---|
Dec. 11, 2018 |
Dec. 31, 2018 |
|
Busch Ranch I Wind Farm | ||
Long-term Purchase Commitment [Line Items] | ||
Utility Plant, Megawatt Capacity | 29 | |
Busch Ranch I Wind Farm | ||
Long-term Purchase Commitment [Line Items] | ||
Number of Megawatts Capacity Purchased | 14.5 | |
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Oct. 01, 2037 | |
AltaGas | ||
Long-term Purchase Commitment [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% | |
AltaGas | Busch Ranch I Wind Farm | ||
Long-term Purchase Commitment [Line Items] | ||
Business Acquisition, Percentage of Voting Interests Acquired | 50.00% |
Commitments And Contingencies: Other Gas Supply Agreements (Details) |
12 Months Ended |
---|---|
Dec. 31, 2018 | |
Purchase Commitment | |
Long-term Purchase Commitment [Line Items] | |
Long Term Contract For Purchase of Fuel, Date of Contract Expiration | Dec. 31, 2044 |
Commitments And Contingencies: Purchase Commitment (Details) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2018
USD ($)
MMBTU
|
Dec. 31, 2017
USD ($)
|
Dec. 31, 2016
USD ($)
|
|
Long-term Purchase Commitment [Line Items] | |||
Term of Evergreen Contracts | 60 days | ||
CIG Rockies | |||
Long-term Purchase Commitment [Line Items] | |||
2019 | 5,803,117 | ||
2020 | 75,075 | ||
2021 | 0 | ||
2022 | 0 | ||
2023 | 0 | ||
Thereafter | 0 | ||
NNG-Ventura | |||
Long-term Purchase Commitment [Line Items] | |||
2019 | 3,650,000 | ||
2020 | 3,660,000 | ||
2021 | 3,650,000 | ||
2022 | 1,810,000 | ||
2023 | 0 | ||
Thereafter | 0 | ||
NWPL-Wyoming | |||
Long-term Purchase Commitment [Line Items] | |||
2019 | 720,000 | ||
2020 | 0 | ||
2021 | 0 | ||
2022 | 0 | ||
2023 | 0 | ||
Thereafter | 0 | ||
Other Natural Gas Indices | |||
Long-term Purchase Commitment [Line Items] | |||
2019 | 236 | ||
2020 | 0 | ||
2021 | 0 | ||
2022 | 0 | ||
2023 | 0 | ||
Thereafter | 0 | ||
Natural Gas, Distribution | |||
Long-term Purchase Commitment [Line Items] | |||
Natural Gas Purchases | $ | $ 27 | $ 65 | $ 31 |
Commitments And Contingencies: Unconditional Purchase Obligations (Details) $ in Thousands |
Dec. 31, 2018
USD ($)
|
---|---|
Power Purchase Agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2019 | $ 22,092 |
2020 | 6,837 |
2021 | 6,203 |
2022 | 6,203 |
2023 | 6,204 |
Thereafter | 0 |
Transportation, Storage, Gathering And Coal Agreements | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2019 | 129,018 |
2020 | 127,326 |
2021 | 118,707 |
2022 | 92,635 |
2023 | 73,919 |
Thereafter | $ 148,363 |
Commitments And Contingencies: Future Purchase Agreement - Related Party (Details) - Wygen I Generating Facility - Purchase Option, Property $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2018
USD ($)
MW
| |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Number of Megawatts Capacity Purchased | MW | 60 |
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration | Dec. 31, 2022 |
Asset Purchase Option | $ | $ 2.1 |
Property, Plant and Equipment, Useful Life | 35 years |
Commitments And Contingencies: Related Party Lease (Details) - Power purchased - Pueblo Airport Generation |
12 Months Ended |
---|---|
Dec. 31, 2018
MW
| |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Lease Expiration Date | Dec. 31, 2031 |
Number of Megawatts Capacity Purchased | 200 |
Commitments And Contingencies: Reimbursement Agreement (Details) - Electric Utilities - USD ($) $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2018 |
Dec. 31, 2017 |
|
Debt Instrument [Line Items] | ||
Long-term debt | $ 544,855 | $ 544,855 |
Industrial Development Revenue Bonds Due 2027 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 10,000 | 10,000 |
Long-term Debt, Maturity Date | Mar. 01, 2027 | |
Industrial Development Revenue Bonds Due 2021 | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 7,000 | $ 7,000 |
Long-term Debt, Maturity Date | Sep. 01, 2021 |
Guarantees (Details) $ in Thousands |
Dec. 31, 2018
USD ($)
|
---|---|
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | $ 94,490 |
Surety Bond | |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | 54,683 |
Performance Guarantee | |
Guarantor Obligations [Line Items] | |
Guarantor, Maximum Exposure | $ 39,807 |
Oil and Gas Reserves (Unaudited): Costs Incurred Oil and Gas (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands |
12 Months Ended |
---|---|
Dec. 31, 2016
USD ($)
| |
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract] | |
Proved Reserves | $ 0 |
Unproved Reserves | 910 |
Exploration Costs | 1,102 |
Development Costs | 4,657 |
Asset Retirement Obligation Incurred | 0 |
Oil and Gas Property Acquisition, Exploration, and Development Activities | $ 6,669 |
Oil and Gas Reserves (Unaudited): Capitalized Costs (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands |
Dec. 31, 2016
USD ($)
|
---|---|
Unproved oil and gas properties | $ 18,547 |
Proved oil and gas properties | 1,043,558 |
Gross capitalized costs | 1,062,105 |
Accumulated depreciation, depletion and amortization and valuation allowances | (1,000,091) |
Net capitalized costs | $ 62,014 |
Oil and Gas Reserves (Unaudited): Results of Operations Oil and Gas (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands |
12 Months Ended |
---|---|
Dec. 31, 2016
USD ($)
| |
Revenue | $ 34,058 |
Production costs | 17,231 |
Depreciation, depletion and amortization | 12,574 |
Impairment of long-lived assets | 106,957 |
Total costs | 136,762 |
Results of operations from producing activities before tax | (102,704) |
Income tax benefit (expense) | 37,916 |
Results of operations from producing activities (excluding general and administrative costs and interest costs) | $ (64,788) |
Oil and Gas Reserves (Unaudited): Unproved Properties (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands |
12 Months Ended |
---|---|
Dec. 31, 2016
USD ($)
| |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | |
Interest Costs, Capitalized During Period | $ 900 |
Leasehold acquisition cost | 963 |
Exploration cost | 532 |
Capitalized interest | 50 |
Total | $ 1,545 |
Oil and Gas Reserves (Unaudited): Standard Measure of Discounted Future Net Cash Flows (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Future cash inflows | $ 246,221 | |
Future production costs | (166,248) | |
Future development costs, including plugging and abandonment | (18,333) | |
Future net cash flows | 61,640 | |
10% annual discount for estimated timing of cash flows | (26,574) | |
Standardized measure of discounted future net cash flows | $ 35,066 | $ 79,028 |
Oil and Gas Reserves (Unaudited): Change in Standard Measure of Discounted Future Cash Net Flows (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Thousands |
12 Months Ended |
---|---|
Dec. 31, 2016
USD ($)
| |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward] | |
Standardized measure - beginning of year | $ 79,028 |
Sales and transfers of oil and gas produced, net of production costs | (4,314) |
Net changes in prices and production costs | (32,698) |
Changes in future development costs | 1,825 |
Revisions of previous quantity estimates | (7,477) |
Accretion of discount | 7,903 |
Sales of reserves | (9,201) |
Standardized measure - end of year | $ 35,066 |
Quarterly Historical Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2018 |
Sep. 30, 2018 |
Jun. 30, 2018 |
Mar. 31, 2018 |
Dec. 31, 2017 |
Sep. 30, 2017 |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2018 |
Dec. 31, 2017 |
Dec. 31, 2016 |
|
Selected Quarterly Financial Information [Line Items] | |||||||||||
Revenue - | $ 501,196 | $ 321,979 | $ 355,704 | $ 575,389 | $ 455,298 | $ 335,611 | $ 341,829 | $ 547,528 | $ 1,754,268 | $ 1,680,266 | $ 1,538,916 |
Operating income (loss) | 114,127 | 65,085 | 69,551 | 148,274 | 117,195 | 79,559 | 69,796 | 150,186 | 397,037 | 416,736 | 336,181 |
Income (loss) from continuing operations | 91,604 | 21,801 | 27,167 | 138,977 | 67,835 | 32,898 | 25,927 | 81,715 | 279,549 | 208,375 | 146,793 |
Net (loss) from discontinued operations | (1,260) | (857) | (2,427) | (2,343) | (13,614) | (1,300) | (616) | (1,569) | (6,887) | (17,099) | (64,162) |
Net income attributable to noncontrolling interest | (3,773) | (3,994) | (2,823) | (3,630) | (3,568) | (3,935) | (3,116) | (3,623) | (14,220) | (14,242) | (9,661) |
Net income (loss) available for common stock | 86,571 | 16,950 | 21,917 | 133,004 | 50,653 | 27,663 | 22,195 | 76,523 | 258,442 | 177,034 | 72,970 |
Amounts attributable to common shareholders: | |||||||||||
Net income from continuing operations | 87,831 | 17,807 | 24,344 | 135,347 | 64,267 | 28,963 | 22,811 | 78,092 | 265,329 | 194,133 | 137,132 |
Net (loss) from discontinued operations | (1,260) | (857) | (2,427) | (2,343) | (13,614) | (1,300) | (616) | (1,569) | (6,887) | (17,099) | (64,162) |
Net income (loss) available for common stock | $ 86,571 | $ 16,950 | $ 21,917 | $ 133,004 | $ 50,653 | $ 27,663 | $ 22,195 | $ 76,523 | $ 258,442 | $ 177,034 | $ 72,970 |
Earnings (loss) per share of common stock, Basic - | |||||||||||
Earnings from continuing operations, Basic (usd per share) | $ 1.52 | $ 0.33 | $ 0.46 | $ 2.54 | $ 1.21 | $ 0.54 | $ 0.43 | $ 1.47 | $ 4.88 | $ 3.65 | $ 2.64 |
(Loss) from discontinued operations per share, Basic (usd per share) | (0.02) | (0.02) | (0.05) | (0.05) | (0.26) | (0.02) | (0.01) | (0.03) | (0.13) | (0.32) | (1.23) |
Total earnings (loss) per share of common stock, Basic (usd per share) | 1.50 | 0.32 | 0.41 | 2.49 | 0.95 | 0.52 | 0.42 | 1.44 | 4.75 | 3.33 | 1.41 |
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Earnings from continuing operations, Diluted (usd per share) | 1.51 | 0.32 | 0.45 | 2.50 | 1.17 | 0.52 | 0.41 | 1.42 | 4.78 | 3.52 | 2.57 |
(Loss) from discontinued operations, Diluted (usd per share) | (0.02) | (0.02) | (0.05) | (0.04) | (0.25) | (0.02) | (0.01) | (0.03) | (0.12) | (0.31) | (1.20) |
Total earnings (loss) per share of common stock, Diluted (usd per share) | $ 1.49 | $ 0.31 | $ 0.40 | $ 2.46 | $ 0.92 | $ 0.50 | $ 0.40 | $ 1.39 | $ 4.66 | $ 3.21 | $ 1.37 |
Deferred Income Tax Expense (Benefit) | $ (24,239) | $ 80,992 | $ 82,704 | ||||||||
Business Combination, Acquisition Related Costs, Net Of Tax | $ 1,300 | $ 200 | $ 300 | $ 900 | |||||||
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Income Tax Expense (Benefit) | 7,600 | ||||||||||
Income Tax Expense (Benefit) | 23,667 | $ (73,367) | $ (59,101) | ||||||||
Discontinued Operations, Held-for-sale or Disposed of by Sale | |||||||||||
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Impairment Of Oil And Gas Properties, Net Of Tax | 13,000 | ||||||||||
True-up from SourceGas Tax Returns | |||||||||||
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Income Tax Expense (Benefit) | $ 4,100 | ||||||||||
Other Restructuring | |||||||||||
Earnings (loss) per share of common stock, Diluted - | |||||||||||
Deferred Income Tax Expense (Benefit) | $ 23,000 | $ 49,000 | $ 73,000 |
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