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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
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x☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2018
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| For the fiscal year ended | December 31, 2019 |
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| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| For the transition period from ___________________ to __________________ |
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| Commission File Number | 001-31303 |
For the transition period from ___________________ to __________________
Commission File Number 001-31303
BLACK HILLS CORPORATION
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| BLACK HILLS CORPORATION |
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| Incorporated in | South Dakota | | IRS Identification Number | 46-0458824 |
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| 7001 Mount Rushmore Road | IRS Identification NumberRapid City | | South Dakota | 57702 |
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| | Rapid City, South Dakota 57702 | 46-0458824 | | | | |
Registrant’s telephone number, including area code | (605) | 721-1700 | | |
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| Securities registered pursuant to Section 12(b) of the Act: |
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common stock of $1.00 par value | BKH | New York Stock Exchange |
Indicate by check mark if the Registrant |
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| Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. |
| Yes | ☒ | | No | ☐ | |
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| Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. |
| Yes | ☐ | | No | ☒ | |
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| Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. |
| Yes | ☒ | | No | ☐ | |
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| Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). |
| Yes | ☒ | | No | ☐ | |
Yes x No o
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No x
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No o
Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).
Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the Registrantregistrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| | Large accelerated filerx | ☒ | | Accelerated filero | ☐ | |
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| | Non-accelerated filero | ☐ | | Smaller reporting companyo | ☐ | |
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| | | | | Emerging growth companyo |
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If an emerging growth company, indicate by check mark if the Registrantregistrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x
State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
At June 30, 2018 $3,239,030,444
Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.
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| Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). |
| Yes | ☐ | | | No | ☒ | | |
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| The aggregate market value of the voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s |
| most recently completed second fiscal quarter, June 30, 2019, was | $4,727,278,183 | |
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| Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. |
| Class | Outstanding at January 31, 20192020 | |
| Common stock, $1.00 par value | 60,003,96561,475,403 |
| shares | |
Documents Incorporated by Reference
Portions of the Registrant’sregistrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 20192020 Annual Meeting of Stockholders to be held on April 30, 2019,28, 2020, are incorporated by reference in Part III of this Form 10-K.
TABLE OF CONTENTS
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| | WEBSITE ACCESS TO REPORTS | |
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| | FORWARD-LOOKING INFORMATION | |
Part I | | | |
| ITEMS 1. and 2. | | |
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| | ITEM 1A. | RISK FACTORS | |
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| | UNRESOLVED STAFF COMMENTS5. | |
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| ITEM 3. | LEGAL PROCEEDINGS | |
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| ITEM 4. | MINE SAFETY DISCLOSURES | |
Part II | | | |
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | |
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| | CONTROLS AND PROCEDURES10. | |
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| ITEM 9B. | OTHER INFORMATION | |
Part III | | | |
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | |
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| | EXECUTIVE COMPENSATION | | |
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| | PRINCIPAL ACCOUNTING FEES AND SERVICES15. | |
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Part IV | | | |
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| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | |
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GLOSSARY OF TERMS AND ABBREVIATIONS
The following terms and abbreviations appear in the text of this report and have the definitions described below:
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| AC | Alternating Current |
| AFUDC | Allowance for Funds Used During Construction |
AltaGas | AltaGas Renewable Energy Colorado LLC, a subsidiary of AltaGas Ltd. |
| AOCI | Accumulated Other Comprehensive Income (Loss) |
| 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, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (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 |
| Availability | The availability factor of a power plant is the percentage of the time that it is available to provide energy. |
| 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 (doing business as Black Hills Energy) |
| 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, providing wholesale electric capacity and energy primarily to our affiliate utilities. |
| Black Hills Energy | The name used to conduct the business of our utility companies |
Black Hills Energy Colorado ElectricServices | 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 Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas supplier acquired in the SourceGas Acquisition |
Programs (doing business as 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.Energy). |
| 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 |
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| 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 builtowned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a 25-year power purchase agreement.agreement expiring in November 2044.
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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 inwhich provides appliance repair services to residential natural gas customers through on-going monthly service agreements. The consolidation of the SourceGas Acquisitionexisting Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories. |
| 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 PowerSouth Dakota Electric and Cheyenne LightWyoming Electric in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014. |
| Choice Gas Program | TheRegulator approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing the unbundling of the natural gascommodity 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.delivery service. |
| City of Gillette | Gillette, Wyoming |
| City of Cheyenne | Cheyenne, Wyoming |
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| Colorado Electric | Black Hills Colorado Electric, LLC, an indirect,a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy). |
| Colorado Gas | Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy). |
Colorado Interstate Gas (CIG)Common Use System (CUS) | Colorado Interstate Natural Gas Pricing IndexThe Common Use System is a joint transmission system we participate in with Basin Electric and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming. |
| Consolidated Indebtedness to Capitalization Ratio | Any Indebtedness outstanding at such time, divided by Capitalcapital at such time. Capital being Consolidated Net-Worthconsolidated net-worth (excluding noncontrolling interest) plus Consolidated Indebtednessconsolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Agreement.Facility. |
| Cooling Degree Day (CDD) | 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 overlocations. |
| Corriedale | Wind project near Cheyenne, Wyoming, that will be a 30-year average.52.5 MW wind farm jointly owned by South Dakota Electric and Wyoming Electric and will serve as the dedicated wind energy supply to the Renewable Ready program. |
| 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. |
| Cushion Gas | 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. |
| 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 |
| Dividend payout ratio | Annual dividends paid on common stock divided by net income from continuing operations available for common stock |
| 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) |
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| 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 takePurchased energy that costs less than that produced with the place of electricity that would have cost more to produce on the utility’s own systemutilities’ owned generation. |
| EIA | Environmental Improvement Adjustment -- annual adjustment mechanism that allows us to recover from customers eligible investments in, and expense related to, new environmental measures. |
| 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. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015. |
| EWG | Exempt Wholesale Generator |
| FASB | Financial Accounting Standards Board |
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| FDIC | Federal Deposit Insurance Corporation |
| FERC | United States Federal Energy Regulatory Commission |
| Fitch | Fitch Ratings Inc. |
| 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 figurerevenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the figureamount are not specified in public rate ordersorders. |
| Happy Jack | Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services |
| Heating Degree Day (HDD) | 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.locations. |
| HomeServe | We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans. |
| Iowa Gas | Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (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 |
| ITC | Investment tax credit |
| Kansas Gas | Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (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 DakotaMontana-Dakota Utilities Co., a regulated utility divisionsubsidiary of MDU Resources Group, Inc. |
| MEAN | Municipal Energy Agency of Nebraska |
MGPMISO | Manufactured Gas PlantMidcontinent Independent System Operator, Inc. |
| MMBtu | Million British thermal units |
MMcf | Million cubic feet |
MMcfe | Million cubic feet equivalent |
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| 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,an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (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.
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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.United States Department of the Interior’s Office of Surface Mining |
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| PacifiCorp | PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway. |
| PCA | Power Cost Adjustment -- annual adjustment mechanism that allows us to pass a portion of prudently-incurred delivered power costs, including fuel, purchased capacity and energy, and transmission costs, through to customers. |
| PCCA | Power Capacity Cost Adjustment -- annual adjustment that allows us to pass the prudently-incurred purchased capacity costs, incremental to costs included in base rates, through to customers. |
| 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 FarmI. |
| PPA | Power Purchase Agreement |
| PRPA | Platte River Power Authority |
| PSA | Power Sales Agreement |
| PSCo | Public Service Company of Colorado |
| Pueblo Airport Generation | 420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012. |
| PTC | Production tax credit |
| 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 matureswas amended and restated on July 30, 2018 and now terminates on July 30, 2023. |
| Renewable Ready | Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers. The Corriedale wind project will provide 52.5 MW of energy for Renewable Ready subscribers in 2023Wyoming and western South Dakota. |
| RMNG | Rocky Mountain Natural Gas a regulatedLLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas utility acquired in the SourceGas Acquisition that provides regulated transmission and wholesale natural gas service to Black Hills Gas Distributionservices in western Colorado (doing business as Black Hills Energy). |
| RSNs | Remarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018. |
SAIDISCADA | System Average Interruption Duration IndexSupervisory control and data acquisition
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| SDPUC | South Dakota Public Utilities Commission |
| SEC | U. S.United States Securities and Exchange Commission |
| Service Guard | Home appliance repair product offering for both natural gas and electric residential customers through on-going monthly service agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories. |
| Service Guard Comfort Plan | New plan that will consolidate Service Guard and CAPP and provide similar services. |
| 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 |
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| 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, operationsInc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming and Montana(doing business as Black Hills Energy). |
| SSIR | System Safety and Integrity Rider |
| System Peak Demand | Represents the highest point of retail 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.hour. |
| TCA | Transmission Cost Adjustment -- adjustments passed throughannual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the customer based on transmission costs that are higher or lower than the costs approved in thenext rate case.review. |
| 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 -- annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers. |
| VEBA | Voluntary Employee Benefit Association |
| VIE | Variable Interest Entity |
| WDEQ | Wyoming Department of Environmental Quality |
| WECC | Western Electricity Coordinating Council |
Winter Storm AtlasWind Capacity Factor | An October 2013 blizzard that impacted South Dakota Electric. It wasMeasures the second most severe blizzardamount of electricity a wind turbine produces in Rapid City’s history.a given time period relative to its maximum potential |
| Working Capacity | Total gas storage capacity minus cushion gas |
| 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 (doing business as Black Hills Energy South Dakota. Our WRDC mine supplies all of the fuel for the plant.Energy) |
| Wyoming Electric | Includes Cheyenne Light’sLight, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric utility operationsservice to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy). |
| Wyoming Gas | Includes Cheyenne Light’sBlack Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas utility operations,services to customers in Wyoming (doing business as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming gas operations
Energy). |
Website Access to Reports
The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information contained on our website is not part of this document.
Forward-Looking Information
This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.Operations.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only as of the date on which the statement is made and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Form 10-K, including statements contained within Item 1A - Risk Factors.Factors.
PART I
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| ITEMS 1 AND 2. | BUSINESS AND PROPERTIES |
History and Organization
Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941. It was formed through the purchase and combination of several existing electric utilities and related assets, some of which had served customers in the Black Hills region since 1883. In 1956, with the purchase of the Wyodak coalWRDC mine, we began producing and selling energy through non-regulated businesses.
We operate our business in the United States, reporting our operating results through our regulated Electric Utilities, regulated Gas Utilities, Power Generation and Mining segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.
Our Electric Utilities segment generates, transmits and distributes electricity to approximately 212,000214,000 electric utility customers in Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 939 MW of generation and 8,8588,892 miles of electric transmission and distribution lines.
Our Gas Utilities segment serves approximately 1,054,0001,066,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate approximately 4,7004,775 miles of intrastate gas transmission pipelines and 41,15841,210 miles of gas distribution mains and service lines, seven natural gas storage sites, over 45,000nearly 49,000 horsepower of compression and nearly 600over 500 miles of gathering lines.
Our Power Generation segment produces electric power from its wind, natural gas and coalcoal-fired generating plants and sells the electric capacity and energy primarily to our utilities under long-term contracts. Our Mining segment produces coal at our mine near Gillette, Wyoming, and sells the coaland delivers it primarily under long-term contracts to adjacent mine-mouth electric generation facilities owned by our Electric Utilities and Power Generation businesses.
Electric Utilities Segment
We conduct electric utility operations through our Colorado, South Dakota and Wyoming and Colorado subsidiaries. Our Electric Utilities generate, transmit and distribute electricity to approximately 212,000 customers in South Dakota, Wyoming, Colorado and Montana. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our own distribution systems. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services through our Tech Services product lines.
Capacity and Demand. System peak demandsdemand for the Electric UtilitiesUtilities’ retail customers for each of the last three years are listed below:
|
| | | | | | | | | |
| | 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 |
|
| | | | | | | | |
| | System Peak Demand (in MW) |
| | 2019 | | 2018 | | 2017 |
| | Summer | Winter | | Summer | Winter | | Summer | Winter |
Colorado Electric (a) | 422 | 297 | | 413 | 313 | | 398 | 299 |
| South Dakota Electric | 335 | 320 |
| 355 | 314 |
| 370 | 310 |
Wyoming Electric (b) | 265 | 247 | | 254 | 238 | | 249 | 230 |
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| (a) | The Colorado Electric July 20182019 summer peak load of 254422 surpassed previous summer peak record load of 249413 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. |
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(b) | The July 2018 summer peak load of 413 surpassed previous summer peak record load of 412 set in July 2016.June 2018. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011. |
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| (b) | The Wyoming Electric July 2019 summer peak load of 265 surpassed previous summer peak record load of 254 set in July 2018. The December 2019 winter peak load of 247 surpassed the previous winter peak record load of 238 set in December 2018. |
Regulated Power Plants. As of December 31, 20182019, our Electric Utilities’ ownership interests in electric generating plants were as follows:
| | | Unit | Fuel Type | Location | Ownership Interest % | Owned Capacity (MW) | Year Installed | Fuel Type | Location | Ownership Interest % | Owned Capacity (MW) | In Service Date |
| Colorado Electric: | | |
Busch Ranch I (a) | | Wind | Pueblo, Colorado | 50% | 14.5 | 2012 |
Peak View (b) | | 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 |
| South Dakota Electric: | | |
Cheyenne Prairie (a) | Gas | Cheyenne, Wyoming | 58% | 55.0 | 2014 | |
Wygen III (b) | Coal | Gillette, Wyoming | 52% | 57.2 | 2010 | |
Cheyenne Prairie (c) | | Gas | Cheyenne, Wyoming | 58% | 55.0 | 2014 |
Wygen III (d) | | Coal | Gillette, Wyoming | 52% | 57.2 | 2010 |
| Neil Simpson II | Coal | Gillette, Wyoming | 100% | 90.0 | 1995 | Coal | Gillette, Wyoming | 100% | 90.0 | 1995 |
Wyodak (c) | Coal | Gillette, Wyoming | 20% | 72.4 | 1978 | |
Wyodak Plant (e) | | Coal | Gillette, Wyoming | 20% | 72.4 | 1978 |
| Neil Simpson CT | Gas | Gillette, Wyoming | 100% | 40.0 | 2000 | Gas | Gillette, Wyoming | 100% | 40.0 | 2000 |
| Lange CT | Gas | Rapid City, South Dakota | 100% | 40.0 | 2002 | Gas | Rapid City, South Dakota | 100% | 40.0 | 2002 |
| Ben French Diesel #1-5 | Oil | Rapid City, South Dakota | 100% | 10.0 | 1965 | 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 | 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 | |
Cheyenne Prairie (c) | | Gas | Cheyenne, Wyoming | 42% | 40.0 | 2014 |
Cheyenne Prairie CT (c) | | Gas | Cheyenne, Wyoming | 100% | 37.0 | 2014 |
| Wygen II | Coal | Gillette, Wyoming | 100% | 95.0 | 2008 | 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 | | | 939.1 | |
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| (a) | Busch Ranch I is operated by Colorado Electric. In 2013, the facility was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act. Black Hills Electric Generation owns the remaining 50% interest in the wind farm. Colorado Electric has a PPA with Black Hills Electric Generation for its share of power from the wind farm. |
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| (b) | The Peak View facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins. Peak View was placed in service in November 2016. |
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| (c) | Cheyenne Prairie a 132 MW natural gas-fired power generation facility supportsserves 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). |
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(b)(d) | Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric has aowns 52% ownership interest,of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our adjacent WRDC coal mine supplies all of the fuel for the plant. |
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(c)(e) | Wyodak Plant, 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. |
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(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. |
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(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. |
The Electric Utilities’ annual weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh for the years ended December 31 was as follows:
| | | Fuel Source (dollars per MWh) | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| Coal | $ | 11.10 |
| $ | 10.95 |
| $ | 11.27 |
| $ | 11.46 |
| $ | 11.10 |
| $ | 10.95 |
|
| | | |
| Natural Gas | $ | 33.42 |
| $ | 34.05 |
| $ | 30.59 |
| $ | 25.92 |
| $ | 33.42 |
| $ | 34.05 |
|
| | | |
Diesel Oil (a) | $ | 329.27 |
| $ | 210.11 |
| $ | 149.13 |
| $ | 209.86 |
| $ | 329.27 |
| $ | 210.11 |
|
| | | |
| Total Average Fuel Cost | $ | 13.53 |
| $ | 12.80 |
| $ | 12.99 |
| |
| Total Weighted Average Fuel Cost | | $ | 13.86 |
| $ | 13.53 |
| $ | 12.80 |
|
| | | |
| Purchased Power - Coal, Gas and Oil | $ | 45.62 |
| $ | 45.63 |
| $ | 48.36 |
| $ | 43.73 |
| $ | 45.62 |
| $ | 45.63 |
|
| | | |
| Purchased Power - Renewable Sources | $ | 54.31 |
| $ | 53.08 |
| $ | 51.95 |
| $ | 48.61 |
| $ | 54.31 |
| $ | 53.08 |
|
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| (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. |
Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended December 31 was as follows:
| | | Power Supply | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| Coal | 32 | % | 32 | % | 33 | % | 30 | % | 32 | % | 32 | % |
| Gas, Oil and Wind | 10 |
| 8 |
| 7 |
| 12 |
| 10 |
| 8 |
|
| Total Generated | 42 |
| 40 |
| 40 |
| 42 |
| 42 |
| 40 |
|
Purchased (a) | 58 |
| 60 |
| 60 |
| 58 |
| 58 |
| 60 |
|
| Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
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| (a) | Wind represents approximately 6%, 6% and 7%6% of our purchased power in 2019, 2018, 2017, and 2016,2017, respectively. |
Purchased Power.Power Purchase and Power Sales Agreements. We have executed various agreementsPPAs to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Key contracts include:
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.
The purchase price related to the option is $2.1 million per MW (65 MWs), adjusted for all depreciated capital additions since 2009, and reduced by depreciation (approximately $5 million per year) over a 35-year life beginning January 1, 2009. The net book value of Wygen I at December 31, 2018 was $75 million and if Wyoming Electric had exercised the purchase option at year-end 2018, the estimated purchase price would have been approximately $139 million;
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.
Power Sales Agreements.Our Electric Utilities also have various long-term power sales agreements.PSAs. Key agreements include:
MDU owns a 25% interestcontracts are disclosed in
Wygen III’s net generating capacity for the lifeNote 19 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;Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
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:
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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 |
Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage transmission lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly own high voltage linesan electric transmission system, referred to as the Common Use System, with Basin Electric and Powder River Energy Corporation.
At December 31, 20182019, our Electric Utilities owned the electric transmission and distribution lines shown below:
| | | Utility | State | Transmission (in Line Miles) | Distribution (in Line Miles) | State | Transmission (in Line Miles) | Distribution (in Line Miles) |
| Colorado Electric | | Colorado | 598 |
| 3,120 |
|
| South Dakota Electric | South Dakota, Wyoming | 1,231 |
| 2,539 |
| South Dakota, Wyoming | 1,219 |
| 2,557 |
|
South Dakota Electric - Jointly Owned (a) | South Dakota, Wyoming | 44 |
| — |
| South Dakota, Wyoming | 43 |
| — |
|
| Wyoming Electric | Wyoming | 49 |
| 1,291 |
| Wyoming | 49 |
| 1,306 |
|
| Colorado Electric | Colorado | 598 |
| 3,106 |
| |
| | | | 1,909 |
| 6,983 |
|
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| (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. See Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. |
South Dakota Electric has firm point-to-point transmission accessMaterial contracts are disclosed in Note 19 of the Notes to deliver upthe Consolidated Financial Statements in this Annual Report on Form 10-K. Additional contracts disclosed below are also key to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the WECC region through December 31, 2023.
South Dakota Electric also has firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming,allowing us to serve our power sales contract with MDU through December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.customer load:
In order to serve Wyoming Electric’s existing load, Wyoming Electric has a network transmission agreement with Western Area Power Association’s Loveland Area Project.
Colorado Electric is party to a joint dispatch agreement with PSCo and Platte River Power Authority.PRPA. This FERC-approved agreement, effective in 2017, is structured to allow PSCo, as administrator, to receive load and generation bid information for all three parties and, on an intra-hour basis, serve the combined utility load utilizing the combined bid generating resources on a least-cost basis. In other words, if one party has excess generation at a lower cost than another party’s generation, the administrator will increase dispatch of the lower-cost generation and decrease dispatch of the higher-cost generation. This results in lower energy costs to customers through more efficient dispatch of low-cost generating resources. Under the agreement, Colorado Electric retains the ability to participate or not participate in the joint dispatch at its discretion.
South Dakota Electric has firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming, to serve our power sales contract with MDU through December 31, 2023, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.
Wyoming Electric has a firm network transmission agreement with Western Area Power Administration’s Loveland Area Project that allows us to serve our existing load in Cheyenne, Wyoming.
Operating Agreements. Our Electric Utilities have the following material operating agreements:
Shared Services Agreements -
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| ◦ | South Dakota Electric, Wyoming Electric, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity chargesis charged for the use of assets located at the Gillette, Wyoming energy complex by the affiliate entity. |
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| ◦ | 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. |
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| ◦ | South Dakota Electric and BHSC are parties to a shared facilities agreement, whereby BHSC is charged for the use of the Horizon Point facility that is owned by South Dakota Electric and BHSC provides certain operations and maintenance services at the facility. |
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| ◦ | South Dakota Electric and Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie. |
Jointly Owned Facilities -
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◦• | South Dakota Electric, the City of Gillette and MDUJointly Owned Facilities agreements 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 sharediscussed in Note 4 of the Wygen III generating facility forNotes to the life of the plant.Consolidated Financial Statements in this Annual Report on Form 10-K. |
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◦ | 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. |
Seasonal Variations of Business. Our Electric Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, demand is often greater in the summer and winter months for cooling and heating, respectively. Because our Electric Utilities have a diverse customer and revenue base, and we have historically optimized the utilization of our electric power supply resources, the impact on our operations may not be as significant when weather conditions are warmer in the winter and cooler in the summer.
Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas. Various legislative or regulatory restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date, these initiatives have not had a material impact on our utilities. In Colorado, our electric utility is subject to rules which may require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-affiliated independent power producers for the right to provide electric energy and capacity for Colorado Electric when resource plans require additional resources.
Rates and Regulation. Our Electric Utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate. Theoperate and the FERC for certain assets. These commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, the rates of other utilities, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities. The following table provides regulatory information for each of our Electric Utilities:
| | | 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 | 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 |
| | | | | |
| 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 |
| South Dakota Electric | WY | 9.9% | 8.13% | 46.7%/53.3% | $46.8 | 10/2014 | ECA | 65% | 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 | SD | Global Settlement | 7.76% | Global Settlement | $543.9 | 10/2014 | ECA, Energy Efficiency Cost Recovery/DSM, TFA, EIA | 70% |
| | FERC | 10.8% | 8.76% | 43%/57% | | 2/2009 | FERC Transmission Tariff | N/A | FERC | 10.8% | 8.76% | 43%/57% | $138.4 (a) | 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 | 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 | 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 | |
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| (a) | Includes $121.3 million in 2019 rate base for the Common Use System formula rate that is updated annually and $17.1 million in rate base for the DC transmission tie that is based on the approved stated rate from 2005. |
The regulatory provisions for recovering the costs to supply electricity vary by state. In all states, subject to thresholds noted below, we have cost adjustment mechanisms for our Electric Utilities that allow us to pass the prudently-incurred cost of fuel and purchased power through to customers. These mechanisms allow the utility operating in that state to collect, or refund the difference between the cost of commodities and certain services embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate review. SomeIn addition, some states allow for recovery of new capital investment placed in which our utilities operate alsoservice between base rate reviews through approved rider tariffs. These tariffs allow the utility operating in that state to automatically adjust rates periodically for the cost of new transmission or environmental improvements and, in some instances, the utility has the opportunity to earn its authorizeda return on new capital investment immediately.the investment.
The significantA summary of mechanisms we have in place includeare shown in the following by utility and state:
South Dakota Electric has:
table below:
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.
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| | | | | | |
| Electric Utility Jurisdiction | Cost Recovery Mechanisms |
| Environmental Cost | Energy Efficiency | Transmission Expense | Fuel Cost | Transmission Capital | Purchased Power |
| Colorado Electric | | þ | þ | þ | þ | þ |
| South Dakota Electric (SD) | þ | þ | þ | þ | þ | þ |
| South Dakota Electric (WY) | | þ | þ | þ | | þ |
| South Dakota Electric (FERC) | | | | | þ | |
| Wyoming Electric | | þ | þ | þ | | þ |
See Note 13 in of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. information regarding current electric rate activity.
An annual adjustment clause which provides forThe significant mechanisms we have in place include 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.following by utility:
An approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff.
In Wyoming, Wyoming Electric has:
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.
In Colorado, Colorado Electric has:
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.
Tariff Filings
On December 17, 2018, South Dakota Electric has:
| |
| • | An approved annual EIA tariff which recovers costs associated with generation plant environmental improvements. South Dakota Electric also has a 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. On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to extend the 6-year moratorium period by an additional 3 years whereby rate increases for these recovery mechanisms will not go into effect prior to July 1, 2026. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for further information. |
An annual cost adjustment clause which provides for the over or under recovery of fuel, transmission and Wyoming Electric filed for approval of new, voluntary renewable energy tariffspurchased power cost incurred to serve customer requests forSouth 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%. For the period of July 1, 2017 through March 31, 2023, 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 energy resources. Requests to approve the voluntary tariffs, known as Renewable Ready Service Tariffs, were submittedresources and firm purchases to the SDPUCcustomer load. In Wyoming, a similar fuel and WPSC. The renewable ready tariffs would provide large commercial and industrial customers and governmental agencies an option to purchase utility-scale renewable energy. As proposed, customers would be able to enter into contracts with Black Hills Energy to purchase renewable energy for periodspurchased power cost adjustment is also in place.
An approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of five to 25 years.South Dakota Electric’s open access transmission tariff.
On September 28, 2018, Wyoming Electric filedhas:
An annual cost adjustment mechanism that allows us to pass the prudently-incurred power costs above costs included in base rates through to electric customers. The annual cost adjustment allows for approvalrecovery of a new innovative tariff to serve blockchain business customers in Wyoming. Request to approve the blockchain tariff, known as Blockchain Interruptible Service (“BCIS”) tariff, was submitted to the WPSC. The BCIS tariff, as proposed, was designed in response to blockchain business recruiting initiatives85% of the statecoal and coal-related cost per kWh variances from base and recovery of Wyoming95% of purchased power, transmission, and would provide the opportunity for Wyoming Electric to attract blockchain business and continue to provide safe and reliable service without negatively impacting existing customers.natural gas cost per kWh variances from base.
Tariff Filings. See Note 13 in of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for tariff filings and additional information regarding current electric rate activity.
Operating Statistics. The following tables summarize information for our Electric Utilities:
| | | | | | | | | | | For the year ended December 31, |
| Degree Days | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| | Actual | Variance from 30-Year Average (b) | Actual | Variance from 30-Year Average (b) | Actual | Variance from 30-Year Average (b) | Actual | Variance from Normal | Actual | Variance from Normal | Actual | Variance from Normal |
| Heating Degree Days: | | | | | | | | | | | | |
| Colorado Electric | | 5,453 |
| (3)% | 5,119 |
| 4% | 4,693 |
| (16)% |
| South Dakota Electric | 7,749 |
| 8% | 6,870 |
| (4)% | 6,402 |
| (10)% | 8,284 |
| 16% | 7,749 |
| 8% | 6,870 |
| (4)% |
| Wyoming Electric | 7,036 |
| (7)% | 6,623 |
| (12)% | 6,363 |
| (14)% | 7,406 |
| 1% | 7,036 |
| (7)% | 6,623 |
| (12)% |
| Colorado Electric | 5,119 |
| 4% | 4,693 |
| (16)% | 4,658 |
| (16)% | |
| | | | | | | | |
Combined (a) | 6,405 |
| 3% | 5,826 |
| (11)% | 5,595 |
| (13)% | 6,813 |
| 5% | 6,405 |
| 3% | 5,826 |
| (11)% |
| | | | | | | | | | | | | |
| Cooling Degree Days: | | | | | | | | | | | | |
| Colorado Electric | | 1,226 |
| 37% | 1,420 |
| 58% | 1,027 |
| 14% |
| South Dakota Electric | 488 |
| (23)% | 709 |
| 11% | 646 |
| (4)% | 404 |
| (36)% | 488 |
| (23)% | 709 |
| 11% |
| Wyoming Electric | 430 |
| 24% | 429 |
| 23% | 460 |
| 31% | 462 |
| 33% | 430 |
| 24% | 429 |
| 23% |
| Colorado Electric | 1,420 |
| 58% | 1,027 |
| 14% | 1,358 |
| 42% | |
| | | | | | | | |
Combined (a) | 902 |
| 29% | 798 |
| 14% | 935 |
| 26% | 791 |
| 14% | 902 |
| 29% | 798 |
| 14% |
________________
| |
| (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) |
| | | For the year ended December 31, | | For the year ended December 31, |
| | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 |
| Residential | | $ | 216,108 |
| $ | 218,558 |
| $ | 210,172 |
| | 1,440,551 |
| 1,450,585 |
| 1,390,952 |
|
| Commercial | | 246,704 |
| 250,894 |
| 258,754 |
| | 2,055,253 |
| 2,034,917 |
| 2,038,495 |
|
| Industrial | | 131,831 |
| 124,668 |
| 122,958 |
| | 1,787,412 |
| 1,682,074 |
| 1,598,755 |
|
| Municipal | | 17,206 |
| 17,871 |
| 18,144 |
| | 157,298 |
| 160,913 |
| 160,882 |
|
| Subtotal Retail Revenue - Electric | | 611,849 |
| 611,991 |
| 610,028 |
| | 5,440,514 |
| 5,328,489 |
| 5,189,084 |
|
Contract Wholesale (a) | | 19,078 |
| 33,688 |
| 30,435 |
| | 368,360 |
| 900,854 |
| 722,659 |
|
| Off-system/Power Marketing Wholesale | | 25,622 |
| 24,800 |
| 21,111 |
| | 701,633 |
| 673,994 |
| 661,263 |
|
| Other | | 56,203 |
| 40,972 |
| 43,076 |
| | — |
| — |
| — |
|
| Total Revenue and Energy Sold | | 712,752 |
| 711,451 |
| 704,650 |
| | 6,510,507 |
| 6,903,337 |
| 6,573,006 |
|
Other Uses, Losses or Generation, net (b) | | — |
| — |
| — |
| | 393,573 |
| 470,250 |
| 468,179 |
|
| Total Revenue and Energy | | 712,752 |
| 711,451 |
| 704,650 |
| | 6,904,080 |
| 7,373,587 |
| 7,041,185 |
|
Less cost of fuel and purchased power (c) | | 268,297 |
| 283,840 |
| 274,363 |
| | | | |
Gross Margin (non-GAAP) (c) (d) | | $ | 444,455 |
| $ | 427,611 |
| $ | 430,287 |
| | | | |
|
| | | | | | | | | | | | | | | | | |
| | | 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.
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Electric Revenue (in thousands) | | Gross Margin (non-GAAP) (d) (in thousands) | | Quantities Sold (MWh) |
| | | For the year ended December 31, | | For the year ended December 31, | | For the year ended December 31, |
| | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 |
Colorado Electric (c) | | $ | 247,332 |
| $ | 251,218 |
| $ | 251,090 |
| | $ | 137,323 |
| $ | 138,901 |
| $ | 140,121 |
| | 2,180,985 |
| 2,151,918 |
| 2,091,676 |
|
South Dakota Electric (a) | | 291,219 |
| 298,080 |
| 288,433 |
| | 218,104 |
| 205,194 |
| 200,795 |
| | 2,798,887 |
| 3,360,396 |
| 3,187,392 |
|
| Wyoming Electric | | 174,201 |
| 162,153 |
| 165,127 |
| | 89,028 |
| 83,516 |
| 89,371 |
| | 1,924,208 |
| 1,861,273 |
| 1,762,117 |
|
| Total Revenue, Gross Margin (non-GAAP), and Quantities Sold | | $ | 712,752 |
| $ | 711,451 |
| $ | 704,650 |
| | $ | 444,455 |
| $ | 427,611 |
| $ | 430,287 |
| | 6,904,080 |
| 7,373,587 |
| 7,041,185 |
|
________________
| |
| (a) | Non-GAAP measure.2019 revenue and purchased power, as well as associated quantities, for a certain wholesale contract have been presented on a net basis. Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This 2019 presentation change has no impact on Gross margin. |
| |
| (b) | Total MWh includes Other Uses, Losses or Generation, net, which is approximately 6%5%, 6%, and 7%6% for Colorado Electric, South Dakota Electric Wyoming Electric, and ColoradoWyoming Electric, respectively. |
| |
| (c) | Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, cost of fuel and purchased power was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in an increase of $6.7 million and $6.0 million, respectively. There were corresponding decreases to Gross margin for both years. These changes had no impact on consolidated financial results. |
| |
| (d) | For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K. |
| | | | | | | | For the year ended December 31, |
| Quantities Generated and Purchased (MWh) | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| | | |
| Coal-fired | 2,368,506 |
| 2,230,617 |
| 2,201,757 |
| 2,226,028 |
| 2,368,506 |
| 2,230,617 |
|
| Natural Gas and Oil | 446,373 |
| 307,815 |
| 343,001 |
| 600,002 |
| 446,373 |
| 307,815 |
|
| Wind | 253,180 |
| 239,472 |
| 80,582 |
| 238,999 |
| 253,180 |
| 239,472 |
|
| Total Generated | 3,068,059 |
| 2,777,904 |
| 2,625,340 |
| 3,065,029 |
| 3,068,059 |
| 2,777,904 |
|
| Purchased | 4,305,528 |
| 4,263,281 |
| 3,965,052 |
| |
Purchased (a) | | 3,839,051 |
| 4,305,528 |
| 4,263,281 |
|
| Total Generated and Purchased | 7,373,587 |
| 7,041,185 |
| 6,590,392 |
| 6,904,080 |
| 7,373,587 |
| 7,041,185 |
|
|
| | | | | | |
| | For the year ended December 31, |
| Quantities Generated and Purchased (MWh) | 2019 | 2018 | 2017 |
| Generated: | | | |
| Colorado Electric | 443,770 |
| 481,446 |
| 397,965 |
|
| South Dakota Electric | 1,768,456 |
| 1,734,222 |
| 1,581,915 |
|
| Wyoming Electric | 852,803 |
| 852,391 |
| 798,024 |
|
| Total Generated | 3,065,029 |
| 3,068,059 |
| 2,777,904 |
|
| Purchased: |
|
|
|
| Colorado Electric | 1,737,215 |
| 1,670,472 |
| 1,693,711 |
|
South Dakota Electric (a) | 1,030,431 |
| 1,626,174 |
| 1,605,477 |
|
| Wyoming Electric | 1,071,405 |
| 1,008,882 |
| 964,093 |
|
| Total Purchased | 3,839,051 |
| 4,305,528 |
| 4,263,281 |
|
| |
|
|
|
|
| Total Generated and Purchased | 6,904,080 |
| 7,373,587 |
| 7,041,185 |
|
________________
| |
| (a) | 2019 purchased power quantities for a wholesale contract have been presented on a net basis. Prior year amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This 2019 presentation change has no impact on Gross margin. |
|
| | | | | | |
| | As of December 31, |
| Customers at End of Year | 2019 | 2018 | 2017 |
| Residential | 183,232 |
| 181,459 |
| 179,911 |
|
| Commercial | 29,921 |
| 29,299 |
| 29,354 |
|
| Industrial | 83 |
| 84 |
| 86 |
|
| Other | 1,024 |
| 1,030 |
| 914 |
|
| Total Electric Customers at End of Year | 214,260 |
| 211,872 |
| 210,265 |
|
|
| | | | | | |
| 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 |
|
|
| | | | | | |
| | As of December 31, |
| Customers at End of Year | 2019 | 2018 | 2017 |
| Colorado Electric | 97,890 |
| 96,645 |
| 95,951 |
|
| South Dakota Electric | 73,052 |
| 72,533 |
| 72,184 |
|
| Wyoming Electric | 43,318 |
| 42,694 |
| 42,130 |
|
| Total Electric Customers at End of Year | 214,260 |
| 211,872 |
| 210,265 |
|
|
| | | | | | |
| 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 |
|
Gas Utilities Segment
We conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries. Our Gas Utilities transport and distribute natural gas through our distribution network to approximately 1,054,0001,066,000 customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-available basis.
We also provide non-regulated services through Black Hills Energy Services.to our regulated customers. Black Hills Energy Services hasprovides natural gas supply to approximately 47,00049,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming providing unbundled natural gas commodity offeringsWyoming. Additionally, we provide services under the regulatory-approved Choice Gas Program. We also sell, install and service air, heating and water-heating equipment, and provide associated repair service and appliance protection plans under various trade names. Service Guard Comfort Plan and CAPP provide appliance repair services to approximately 62,000 and 28,000 residential customers, respectively, through Company technicians and third-party service providers, typically through on-going monthly service agreements. Tech Services serves gas transportation customers throughout our service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.also offer HomeServe products.
We procure natural gas for our distribution customers from a diverse mix of producers, processors and marketers and generally use hedging, physical fixed-price purchases and market-based price purchases to achieve dollar-cost averaging within our natural gas portfolio. The majority of our procured natural gas is transported in interstate pipelines under firm transportation service agreements with Colorado Interstate Gas Company, Enable Gas Transmission, Tallgrass Interstate Gas Transmission, Natural Gas Pipeline Company of America, Northern Natural Gas, Panhandle Eastern Pipeline Company, Southern Star Central Gas Pipeline, Black Hills Shoshone Pipeline, TransColorado Gas Transmission, WBI Energy Transmission, Rocky Mountain Natural Gas, Ozark Gas Transmission, Liberty Utilities, Texas Eastern Transmission Pipeline, WestGas InterState Pipeline, Public Service Company of Colorado and Red Cedar Gas Gathering.agreements.
In addition to company-owned storage assets in Arkansas, Colorado and Wyoming, we also contract with many of the third-party transportation providers noted above for natural gas storage service to provide gas supply during the winter heating season and to meet peak day customer demand for natural gas.
The following table summarizes certain information regarding our regulated underground gas storage facilities as of December 31, 2018:2019:
|
| | | | | | | | | |
| | 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 |
|
|
| | | | | | | | | |
| | State | Working Capacity (Mcf) | Cushion Gas (Mcf) | Total Capacity (Mcf) | Maximum Daily Withdrawal Capability (Mcfd) |
| |
| | Arkansas | 8,442,700 |
| 13,149,040 |
| 21,591,740 |
| 196,000 |
|
| | Colorado | 2,360,895 |
| 6,165,315 |
| 8,526,210 |
| 30,000 |
|
| | Wyoming | 5,733,900 |
| 17,145,600 |
| 22,879,500 |
| 36,000 |
|
| | Total | 16,537,495 |
| 36,459,955 |
| 52,997,450 |
| 262,000 |
|
________________
| |
(a) | Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure. |
The following tables summarize certain operating information for our Gas Utilities.
| | | System Infrastructure (in line miles) as of | Intrastate Gas Transmission Pipelines | Gas Distribution Mains | Gas Distribution Service Lines | Intrastate Gas Transmission Pipelines | Gas Distribution Mains | Gas Distribution Service Lines |
| December 31, 2018 |
| December 31, 2019 | | Intrastate Gas Transmission Pipelines | Gas Distribution Mains | Gas Distribution Service Lines |
| Arkansas | 932 |
| 4,803 |
| 1,122 |
|
| Colorado | 689 |
| 6,699 |
| 2,457 |
| 693 |
| 6,814 |
| 2,554 |
|
| Nebraska | 1,263 |
| 8,539 |
| 3,203 |
| |
| Iowa | 164 |
| 2,791 |
| 2,667 |
| 165 |
| 2,813 |
| 2,138 |
|
| Kansas | 325 |
| 2,868 |
| 1,347 |
| 330 |
| 2,910 |
| 1,355 |
|
| Nebraska | | 1,311 |
| 8,664 |
| 3,230 |
|
| Wyoming | 1,327 |
| 3,447 |
| 1,215 |
| 1,334 |
| 3,472 |
| 1,219 |
|
| Total | 4,700 |
| 29,147 |
| 12,011 |
| 4,775 |
| 29,553 |
| 11,657 |
|
| | | | | | | | | | | | | For the year ended December 31, |
| Degree Days | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
| | Actual | Variance From 30-Year Average (c) | | Actual | Variance From 30-Year Average (c) | | Actual | Variance From 30-Year Average (c) | Actual | Variance From Normal | | Actual | Variance From Normal | | Actual | Variance From Normal |
| Heating Degree Days: | | | | | | | | | | | | |
Arkansas (a) | 4,169 |
| 3% | | 3,295 |
| (19)% | | 2,397 |
| (41)% | 3,897 |
| (4)% | | 4,169 |
| 3% | | 3,295 |
| (19)% |
| Colorado | 6,136 |
| (7)% | | 5,728 |
| (14)% | | 5,762 |
| (13)% | 6,672 |
| 1% | | 6,136 |
| (7)% | | 5,728 |
| (14)% |
| Nebraska | 6,563 |
| 6% | | 5,554 |
| (10)% | | 5,457 |
| (12)% | |
| Iowa | 7,192 |
| 6% | | 6,149 |
| (9)% | | 5,997 |
| (11)% | 7,200 |
| 6% | | 7,192 |
| 6% | | 6,149 |
| (9)% |
Kansas (a) | 5,242 |
| 7% | | 4,452 |
| (9)% | | 4,307 |
| (12)% | 5,190 |
| 6% | | 5,242 |
| 7% | | 4,452 |
| (9)% |
| Nebraska | | 6,578 |
| 7% | | 6,563 |
| 6% | | 5,554 |
| (10)% |
| Wyoming | 7,425 |
| (1)% | | 7,123 |
| (5)% | | 6,750 |
| (10)% | 8,010 |
| 7% | | 7,425 |
| (1)% | | 7,123 |
| (5)% |
Combined (b) | 6,628 |
| 2% | | 5,862 |
| (10)% | | 5,823 |
| (11)% | 6,840 |
| 5% | | 6,628 |
| 2% | | 5,862 |
| (10)% |
________________
| |
| (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. Thehave weather normalization mechanisms in both Arkansas and Kansas minimizethat mitigate the weather impact on gross margins (a non-GAAP measure).margins. |
| |
| (b) | The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. 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. |
Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as market price. In particular, demand is often greater in the winter months for heating. Natural gas is used primarily for residential and commercial heating, so the demand for this product depends heavily upon weather throughout our service territories and as a result, a significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters. Demand for natural gas can also be impacted by summer weather patterns that are cooler than normal and/or provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation.
Competition. We generally have limited competition for the retail distribution of natural gas in our service areas. Various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives are aimed at increasing competition. To date, these initiatives have not had a material impact on our utilities. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial customers, in instances where independent marketers displace us as the seller of natural gas, we still collect a distribution charge for transporting the gas through our distribution network.
Rates and Regulation. Our Gas Utilities are subject to the jurisdiction of the public utilitiesutility commissions in the states where they operate. TheThese commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, the rates of other utilities, general economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities.
Our Gas Utilities are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure that they recover all the costs prudently incurred in purchasing gas for their customers. In addition to natural gas cost recovery mechanisms, we have other cost recovery mechanisms, such as regulatory riders, which vary by utility, but allow us to recover certain costs or earn a return on capital investments, such as those related to energy efficiency plansplan costs and system safety and integrity investments. The following table provides regulatory information for each of our natural gas utilities:
| | | 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 | 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: | Gas Utilities: | | 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
| 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 or Regulatory Mandated Expenditures, 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 | 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
| CO | 10.0% | 8.02% | 49.52%/ 50.48% | $127.1 | 12/2010 | GCA, Energy Efficiency Cost Recovery/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
| 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 | $109.2 | 2/2011 | GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism, Gas Supply Optimization revenue sharing | IA | Global Settlement | $109.2 | 2/2011 | GCA, Energy Efficiency Cost Recovery, Capital Infrastructure Automatic Adjustment Mechanism, Farm Tap Tracker Adjustment, Gas Supply Optimization revenue sharing |
| Kansas Gas | KS | 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 | KS | 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 | 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, Farm Tap Recovery Mechanism |
| 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
| 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 | WY | 9.4% | 6.98 | 49.77%/50.23% | $354.4 | 3/2020 | GCA, Energy Efficiency Cost Recovery, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program |
| 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 is adjusted to remove current liabilities from rate casereview 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 oftotals $69.8 million excludes those amounts allocated to serve non-jurisdictional and agricultural customers and is used for calculation of jurisdictional base rates. |
All of our Gas Utilities, except where the Choice Gas Program is the only option, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer between rate reviews. Some of the mechanisms we have in place include the following:
|
| | | | | | | | |
| 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.Distribution | 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.Distribution | | þ | þ | | | | | |
Wyoming Gas (a) | þ | þ | | | | þ | | |
Wyoming Gas Dist. | | | | | | þ | | þ |
__________
| |
| (a) | The Wyoming Gas integrity rider is effective March 1, 2020. |
(a) DSM/Energy Efficiency is only applicable to Cheyenne Light.
See Note 13 in of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current natural gas rate activity.
Operating Statistics
2016 includes results from the acquired SourceGas utilities starting February 12, 2016.
| | | | | | | | | | | | | | | | | | | | | | Revenue (in thousands) | | Gross Margin (non-GAAP) (a) (in thousands) | | Quantities Sold and Transported (Dth) |
| | | Revenue (in thousands) | | Gross Margin (a) (in thousands) | | Quantities Sold and Transported (Dth) | | For the year ended December 31, | | For the year ended December 31, | | For the year ended December 31, |
| | | 2018 | 2017 | 2016 | | 2018 | 2017 | 2016 | | 2018 | 2017 | 2016 | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 |
| | | | | | | | | | | | | |
| Residential | | $ | 567,785 |
| $ | 499,852 |
| $ | 433,106 |
| | $ | 276,858 |
| $ | 255,626 |
| $ | 228,512 |
| | 65,352,164 |
| 54,645,598 |
| 49,390,451 |
| | $ | 551,701 |
| $ | 567,785 |
| $ | 499,852 |
| | $ | 285,802 |
| $ | 276,858 |
| $ | 255,626 |
| | 66,956,080 |
| 65,352,164 |
| 54,645,598 |
|
| Commercial | | 214,718 |
| 197,054 |
| 162,547 |
| | 82,529 |
| 78,249 |
| 67,375 |
| | 30,753,361 |
| 27,315,871 |
| 24,037,861 |
| | 212,229 |
| 214,718 |
| 197,054 |
| | 88,264 |
| 82,529 |
| 78,249 |
| | 32,241,441 |
| 30,753,361 |
| 27,315,871 |
|
| Industrial | | 26,466 |
| 24,454 |
| 21,245 |
| | 7,056 |
| 6,226 |
| 5,601 |
| | 6,309,211 |
| 5,855,053 |
| 5,737,430 |
| | 24,832 |
| 26,466 |
| 24,454 |
| | 8,053 |
| 7,056 |
| 6,226 |
| | 6,548,023 |
| 6,309,211 |
| 5,855,053 |
|
Other (b) | | (7,899 | ) | 8,647 |
| 12,694 |
| | (7,899 | ) | 8,647 |
| 12,694 |
| | — |
| — |
| — |
| |
| Other | | | (1,361 | ) | (7,899 | ) | 8,647 |
| | (1,361 | ) | (7,899 | ) | 8,647 |
| | — |
| — |
| — |
|
| Total Distribution | | 801,070 |
| 730,007 |
| 629,592 |
| | 358,544 |
| 348,748 |
| 314,182 |
| | 102,414,736 |
| 87,816,522 |
| 79,165,742 |
| | 787,401 |
| 801,070 |
| 730,007 |
| | 380,758 |
| 358,544 |
| 348,748 |
| | 105,745,544 |
| 102,414,736 |
| 87,816,522 |
|
| | | | | | | | | | | | | |
| Transportation and Transmission | | 141,854 |
| 135,824 |
| 139,490 |
| | 141,850 |
| 135,824 |
| 139,282 |
| | 148,299,003 |
| 141,600,080 |
| 126,927,565 |
| | 144,710 |
| 141,854 |
| 135,824 |
| | 144,710 |
| 141,850 |
| 135,824 |
| | 153,101,264 |
| 148,299,003 |
| 141,600,080 |
|
| | | | | | | | | | | | | |
| Total Regulated | | 942,924 |
| 865,831 |
| 769,082 |
| | 500,394 |
| 484,572 |
| 453,464 |
| | 250,713,739 |
| 229,416,602 |
| 206,093,307 |
| | 932,111 |
| 942,924 |
| 865,831 |
| | 525,468 |
| 500,394 |
| 484,572 |
| | 258,846,808 |
| 250,713,739 |
| 229,416,602 |
|
| | | | | | | | | | | | | |
| Non-regulated Services | | 82,383 |
| 81,799 |
| 69,261 |
| | 62,760 |
| 53,455 |
| 32,714 |
| | — |
| — |
| — |
| | 77,919 |
| 82,383 |
| 81,799 |
| | 58,664 |
| 62,760 |
| 53,455 |
| | — |
| — |
| — |
|
| | | | | | | | | | | | | |
| 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 |
| |
| Total Revenue, Gross Margin (non-GAAP) and Quantities Sold | | | $ | 1,010,030 |
| $ | 1,025,307 |
| $ | 947,630 |
| | $ | 584,132 |
| $ | 563,154 |
| $ | 538,027 |
| | 258,846,808 |
| 250,713,739 |
| 229,416,602 |
|
__________
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Revenue (in thousands) | | Gross Margin (non-GAAP) (a) (in thousands) | | Quantities Sold & Transported (Dth) |
| | | For the year ended December 31, | | For the year ended December 31, | | For the year ended December 31, |
| | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 |
| | | | | | | | | | | | | |
| Arkansas | | $ | 185,201 |
| $ | 176,660 |
| $ | 153,691 |
| | $ | 115,899 |
| $ | 100,917 |
| $ | 94,007 |
| | 30,496,243 |
| 30,931,390 |
| 26,491,537 |
|
| Colorado | | 199,369 |
| 188,002 |
| 180,852 |
| | 106,776 |
| 99,851 |
| 100,718 |
| | 33,908,529 |
| 29,857,063 |
| 28,436,744 |
|
| Iowa | | 151,619 |
| 161,843 |
| 143,446 |
| | 70,290 |
| 68,384 |
| 66,619 |
| | 41,795,729 |
| 40,668,682 |
| 37,013,645 |
|
| Kansas | | 105,906 |
| 112,306 |
| 105,576 |
| | 58,020 |
| 55,226 |
| 53,841 |
| | 32,650,854 |
| 31,387,672 |
| 28,251,947 |
|
| Nebraska | | 255,622 |
| 278,969 |
| 252,631 |
| | 155,901 |
| 164,513 |
| 154,259 |
| | 81,481,192 |
| 81,658,938 |
| 73,890,509 |
|
| Wyoming | | 112,313 |
| 107,527 |
| 111,434 |
| | 77,246 |
| 74,263 |
| 68,583 |
| | 38,514,261 |
| 36,209,994 |
| 35,332,220 |
|
| Total Revenue, Gross Margin (non-GAAP) and Quantities Sold | | $ | 1,010,030 |
| $ | 1,025,307 |
| $ | 947,630 |
| | $ | 584,132 |
| $ | 563,154 |
| $ | 538,027 |
| | 258,846,808 |
| 250,713,739 |
| 229,416,602 |
|
________________
| |
(b) | Other revenue andFor further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in 2018 reflects the impactItem 7 of revenue reserved in accordance with the TCJA.this Annual Report on Form 10-K. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
|
|
| | | | | | |
| | As of December 31, |
| Customers at End of Year | 2019 | 2018 | 2017 |
| | | | |
| Residential | 831,351 |
| 821,624 |
| 806,744 |
|
| Commercial | 82,912 |
| 82,498 |
| 86,461 |
|
| Industrial | 2,208 |
| 2,221 |
| 2,214 |
|
| Transportation/Other | 149,971 |
| 147,550 |
| 146,839 |
|
| Total Customers at End of Year | 1,066,442 |
| 1,053,893 |
| 1,042,258 |
|
__________
|
| | | | | | |
| 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 |
|
|
| | | | | | |
| | As of December 31, |
| Customers at End of Year | 2019 | 2018 | 2017 |
| | | | |
| Arkansas | 174,447 |
| 171,978 |
| 169,303 |
|
| Colorado | 191,950 |
| 186,759 |
| 181,876 |
|
| Iowa | 159,641 |
| 158,485 |
| 157,444 |
|
| Kansas | 115,846 |
| 114,840 |
| 114,082 |
|
| Nebraska | 293,576 |
| 291,723 |
| 290,264 |
|
| Wyoming | 130,982 |
| 130,108 |
| 129,289 |
|
| Total Customers at End of Year | 1,066,442 |
| 1,053,893 |
| 1,042,258 |
|
__________
| |
(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 |
|
Utility Regulation Characteristics
State Regulations
Certain states where we conduct electric utility operations have adopted renewable energy portfolio standards that require or encourage our Electric Utilities to source, by a certain future date, a minimum percentage of the electricity delivered to customers from renewable energy generation facilities. As of December 31, 20182019, we were subject to the following renewable energy portfolio standards or objectives:
| |
| • | 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 have been and currently remain in compliance with these standards. |
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.
On April 25, 2018, Colorado Electric received approval from the CPUC to contract withNovember 26, 2019, Black Hills Electric Generation to purchase 60 MW ofplaced in service Busch Ranch II. Black Hills Electric Generation provides the wind energy through a 25-year PPA. Thegenerated from Busch Ranch II wind project is currentlyto Colorado Electric under construction and is expected to bea 25-year PPA, which expires in service by the end of 2019.November 2044. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard. This renewable energy project was originally submitted in response to Colorado Electric’s electric resource plan filed June 3, 2016, which also provides for additional small solar and community solar gardens as part of the compliance plan.
| |
| • | 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. |
On November 7, 2016, Colorado Electric took ownership of Peak View, a $109 million, 60 MW wind project located near Colorado Electric's Busch Ranch I Wind Farm. Peak View achieved commercial operation on November 7, 2016. This renewable energy project was originally submitted in response to Colorado Electric’s all-source generation request on May 5, 2014. The CPUC’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Energy Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which, Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility.
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| • | 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. |
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| • | Wyoming. Wyoming currently has no renewable energy portfolio standard. |
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.
Absent a specific renewable energy mandate in the territories we serve, our current strategy is to prudently incorporateproactively integrate alternative and renewable energy into our resource supply.utility energy supply while mitigating customer rate impacts. Mandatory portfolio standards have increased, and wouldwill likely continue to increase, the power supply costs of our Electric Utilities’ operations. Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to secure full recovery of the costs we pay to be in compliance with standards or objectives. We cannot at this time reasonably forecast the potential costs associated with any new renewable energy standards that have been or may be proposed at the federal or state level.
Federal Regulation
Energy Policy Act. Black Hills CorporationBHC is a holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and a holding companiescompany regulated by FERC under the Federal Power Act and PUHCA 2005.
Federal Power Act. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must maintain tariffs and rate schedules on file with FERC that govern the rates, and terms and conditions for the provision of FERC-jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their affiliates. Our public Electric Utilities’ subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.
Our Electric Utilities Black Hills Colorado IPP and Black Hills WyomingPower Generation entities are authorized by FERC to make wholesale sales of electric capacity and energy at market-based rates under tariffs on file with FERC. As a condition of their market-based rate authority, each files Electric Quarterly Reports with FERC. Our Electric Utilities own and operate FERC-jurisdictional interstate transmission facilities and provide open access transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to their compliance with FERC’s regulations.
The Federal Power Act authorizes FERC to certify and oversee a national electric reliability organization with authority to promulgate and enforce mandatory reliability standards applicable to all users, owners and operators of the bulk-power system. FERC has certified NERC as the electric reliability organization. NERC has promulgated mandatory reliability standards and NERC, in conjunction with regional reliability organizations that operate under FERC’s and NERC’s authority and oversight, enforces those mandatory reliability standards.
PUHCA 2005. PUHCA 2005 gives FERC authority with respect to the books and records of a utility holding company. As a utility holding company with a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.
Power Generation Segment
Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops, constructs and operates our non-regulated power plants. As of December 31, 2018,2019, we held varying interests in independent power plants operating in Wyoming and Colorado with a total net ownership of approximately 283423 MW.
We produce electric power from our generating plants and sell the electric capacity and energy, primarily to affiliates under a combination of mid- to long-term contracts, which mitigates the impact of a potential downturn in future power prices. We currently sell a substantial majority of our non-regulated generating capacity under contracts having terms greater than one year.
As of December 31, 2018,2019, the power plant ownership interests held by our Power Generation segment include:
| | | Power Plants | Fuel Type | Location | Ownership Interest | Owned Capacity (MW) | In Service Date | Fuel Type | Location | Ownership Interest | Owned Capacity (MW) | In Service Date |
Wygen I | Coal | Gillette, Wyoming | 76.5% | 68.9 |
| 2003 | Coal | Gillette, Wyoming | 76.5% | 68.9 |
| 2003 |
Pueblo Airport Generation (a) | Gas | Pueblo, Colorado | 50.1% | 200.0 |
| 2012 | Gas | Pueblo, Colorado | 50.1% | 200.0 |
| 2012 |
Busch Ranch I | Wind | Pueblo, Colorado | 50.0% | 14.5 |
| 2012 | Wind | Pueblo, Colorado | 50.0% | 14.5 |
| 2012 |
Busch Ranch II (c) (e) | | Wind | Pueblo, Colorado | 100.0% | 60.0 |
| 2019 |
Top of Iowa (d) (e) | | Wind | Joice, Iowa | 100.0% | 80.0 |
| 2019 |
| | | 283.4 |
| | | 423.4 |
| |
_________________________
| |
| (a) | The Wygen I generation facility is a mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5% of the plant and MEAN owns the remaining 23.5%. |
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| (b) | On December 11, 2018, Black Hills Colorado IPP owns and operates this facility.Electric Generation purchased a 50% ownership interest in Busch Ranch I. This facility provides capacityoriginally qualified under the Section 1603 program grant in lieu of ITCs. |
| |
| (c) | On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II. |
| |
| (d) | On February 5, 2019, Black Hills Electric Generation purchased 80 MW of wind generating assets in Iowa. A third-party operates the facility and we sell the wind energy to Colorado Electricgenerated in the MISO market. |
| |
| (e) | This facility qualifies for PTCs at $25/MWh under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital leaseIRC 45 during the 10-year period beginning on the accompanying Consolidated Financial Statements.date the facility was originally placed in service. |
Black Hills Wyoming - Wygen I. The Wygen I generation facility is a mine-mouth, coal-firedPower Sales Agreements. Our Power Generation facilities have various long-term power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5%sales agreements. See Note 19 of the plant and MEAN owns the remaining 23.5%. We sell 60 MW of unit-contingent capacity and energy from this plant to Wyoming Electric under a PPA that expires on December 31, 2022. We sell excess power from our generating capacity into the wholesale power markets when it is available and economical to do so. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s
ownership interest in the Wygen I facility through 2019. See the purchased power discussion within the Electric Utilities segment above about Wyoming Electric’s 2018 integrated resource plan which included a recommendationNotes to the WPSC to acquire Wygen I.Consolidated Financial Statements in this Annual Report on Form 10-K for further information.
Black Hills Colorado IPP - Pueblo Airport Generation. The Pueblo Airport Generating Station consists of two 100 MW combined-cycle gas-fired power generation plants located at a site shared with Colorado Electric. The plants commenced operation on January 1, 2012 and the assets are accounted for as a capital lease under a 20-year PPA with Colorado Electric, which expires on December 31, 2031. Under the PPA with Colorado Electric, any excess capacity and energy shall be for the benefit of Colorado Electric.
Black Hills Electric Generation (BHEG) - Busch Ranch I. 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 share of energy from the wind farm to Colorado Electric through a new PPA which has the same terms as the PPA it replaces that Colorado Electric had with AltaGas, expiring in October 2037.
Third Party Noncontrolling Interest in Subsidiary
Subsidiary. In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million to a third party buyer. Black Hills Electric Generation is the operatorSee Note 12 of the facility, which is contractedNotes to provide capacity and energy through 2031 to Colorado Electric. Proceeds from the sale were used to pay down short-term debt andConsolidated Financial Statements in this Annual Report on Form 10-K for other general corporate purposes. The operating results for Black Hills Colorado IPP remain consolidated with Black Hills Electric Generation, as Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest.additional information.
The following table summarizes MWh for our Power Generation segment:
| | | | | | | | For the year ended December 31, |
Quantities Sold, Generated and Purchased (MWh) (a) | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| 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 |
| — |
| — |
| |
| Black Hills Colorado IPP | | 935,997 |
| 1,000,577 |
| 943,618 |
|
Black Hills Wyoming(b) | | 629,788 |
| 582,938 |
| 645,810 |
|
Black Hills Electric Generation (c) | | 167,296 |
| 5,873 |
| — |
|
| Total Sold | 1,589,388 |
| 1,589,428 |
| 1,868,513 |
| 1,733,081 |
| 1,589,388 |
| 1,589,428 |
|
| | | |
| 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 |
| — |
| — |
| |
| Black Hills Colorado IPP | | 935,997 |
| 1,000,577 |
| 943,618 |
|
Black Hills Wyoming (b) | | 557,119 |
| 501,945 |
| 577,124 |
|
Black Hills Electric Generation (c) | | 167,296 |
| 5,873 |
| — |
|
| Total Generated | 1,508,395 |
| 1,520,742 |
| 1,767,495 |
| 1,660,412 |
| 1,508,395 |
| 1,520,742 |
|
| | | |
| Purchased | | |
| Black Hills Wyoming | 83,213 |
| 69,377 |
| 85,993 |
| |
Black Hills Wyoming (b) | | 74,199 |
| 83,213 |
| 69,377 |
|
| Total Purchased | 83,213 |
| 69,377 |
| 85,993 |
| 74,199 |
| 83,213 |
| 69,377 |
|
____________________
| |
| (a) | Company use and losses are not included in the quantities sold, generated and purchased. |
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| (b) | The decreaseUnder the 20-year economy energy PPA (discussed in 2017 was driven byNote 19 of the jointNotes to the Consolidated Financial Statements in this Annual Report on Form 10-K) with the City of Gillette, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement ColoradoBlack Hills Wyoming has with South Dakota Electric joined in 2017. See details of this agreement above in the Electric Utilities segment.to cover energy imbalances. |
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| (c) | The decreaseBlack Hills Electric Generation amounts in this table are related to wind facilities held by our Power Generation segment. Change from 2018 wasto 2019 is driven by a planned outage at Wygen I.acquisition, and placing in service, of new wind assets. |
Operating Agreements. Our Power Generation segment has the following material operating agreements:
Economy Energy PPA and other ancillary agreements
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◦• | 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-yearWyoming’s economy energy PPA that contains a sharing arrangementand other ancillary agreements are discussed in whichNote 19 of the parties shareNotes to the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.Consolidated Financial Statements in this Annual Report on Form 10-K. |
Operating and Maintenance Services Agreement
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| ◦ | In conjunction with the sale of thea noncontrolling interest on April 14,in 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 frombecame effective on 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
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| ◦ | South Dakota Electric, Wyoming Electric and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity chargesis charged for the use of assets by the affiliate entity. |
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| ◦ | 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. |
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| ◦ | 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.Prairie. |
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| ◦ | Black Hills Colorado IPP and Black Hills Wyoming receive certain staffing and management services from BHSC. |
Jointly Owned Facilities
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◦• | Black Hills Wyoming and MEANJointly owned facilities agreements are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance on its sharediscussed in Note 4 of the Wygen I generating facility overNotes to the life of the plant.Consolidated Financial Statements in this Annual Report on Form 10-K. |
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◦ | 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. |
Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess.
With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity and foster competition within the wholesale electricity markets. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for independent power producers in some regions.
The Energy Policy Act of 1992. The passage of the Energy Policy Act of 1992 encouraged independent power production by providing certain exemptions from regulation for EWGs. EWGs are exclusively in the business of owning or operating, or both owning and operating, eligible power facilities and selling electric energy at wholesale. EWGs are subject to FERC regulation, including rate regulation. We own threefive EWGs: Wygen I, 200 MW (two 100 MW combined-cycle gas-fired units) at the
Pueblo Airport Generating Station, and Black Hills Electric Generation’s interest inGeneration, Busch Ranch I.I, Busch Ranch II and Top of Iowa. Our EWGs were granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates.
Mining Segment
Our Mining segment operates through our WRDC subsidiary. We surface mine, process and sell primarily low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC coal mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin. The Powder River Basin contains one of the largest coal reserves in the United States.eastern Wyoming. We produced approximately 4.13.7 million tons of coal in 2018.2019.
During our surface mining operations, we strip and store the topsoil. We then remove the overburden (earth and rock covering the coal) with heavy equipment. Removal of the overburden typically requires drilling and blasting. Once the coal is exposed, we drill, fracture and systematically remove it, using front-end loaders and conveyors to transport the coal to the mine-mouth generating facilities. We reclaim disturbed areas as part of our normal mining activities by back-filling the pit with overburden removed during the mining process. Once we have replaced the overburden and topsoil, we reestablish vegetation and plant life in accordance with our approved post-mining topography plan.
In a basin characterized by thick coal seams, our overburden ratio, a comparison of the cubic yards of dirt removed to a ton of coal uncovered, has in recent years trended upwards. The overburden ratio at December 31, 20182019 was 2.202.30 which increased from the prior year as we continued mining in areas with higher overburden. We expect our stripping ratio to be approximately 2.262.18 by the end of 20192020 as we mine in areas with comparable overburden.
Mining rights to the coalreserves are based on fourthree federal leases and one state lease. The federal leases expire between April 30, 2019March 31, 2021 and September 30, 2025 and the state lease expires on August 1, 2023. The duration of the leases varies; however, the lease terms generally are extended to the exhaustion of economically recoverable reserves, as long as active mining continues. We pay federal and state royalties of 12.5% of the selling price of all coal. As of December 31, 2018,2019, we estimated our recoverable coal reserves to be approximately 189185 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable coal reserve life is equal to approximately 4650 years at the current production levels. Our recoverable coal reserve estimates are periodically updated to reflect past coal production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable coal reserves include reserves that can be economically and legally extracted at the time of their determination. We use various assumptions in preparing our estimate of recoverable coal reserves. See Risk Factors under Mining for further details.
Substantially all of our coalthe mine’s production is currently sold under contracts to:
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;
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| • | The 362 MW Wyodak Plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 375,000 tons per year for its 20% share of the power plant, subject to adjustments for planned outages. This contract expires December 31, 2022 and negotiations are underway to extend the contract; |
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.
Our Mining segment sells coal to South Dakota Electric and Wyoming Electric for all of their requirements under cost-based agreements that regulate earnings from these affiliate coal sales to a specified return on our coal mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above A-rated utility bondsMoody’s A-Rated Utility Bond Index applied to our Mining investment base. South Dakota Electric made a commitment to the SDPUC, the WPSC and the City of Gillette that coal for South Dakota Electric’s operating plants would be furnished and priced as provided by that agreement for the life of the Neil Simpson II plant and through June 1, 2060, for Wygen III. The agreement with Wyoming Electric provides coal for the life of the Wygen II plant.
The price of unprocessed coal sold to PacifiCorp for the Wyodak plantPlant is determined by the coal supply agreement described above. The agreement includesincluded a price adjustment in 2019. The price adjustment essentially allowsallowed us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment iswas based on the market price of coal plus considerations for the avoided costs of rail transportation and a coalan unloading facility, which PacifiCorp would have to incur if it purchased coal from another mine. In addition, the agreement also providesprovided for the monthly escalation of coal price based on an escalation factor.
In October 2019, negotiations were completed for the price re-opener in the contract with Wyodak Plant. The new price was
reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton. The current contract price ($19.08 per ton as of December 2018) is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of a coalan unloading facility (approximately 30% of current price); and 3) a rolling 12-month average of the Coal Daily spot market price of 8,400 Btu Powder River Basin coal (approximately 50% of current price). With respect to the 2019 coal price re-opener, we expect the transportation and unloading costs to escalate slightly. The current trailing 12-month spot price of 8,400 Btu Powder River Basin coal, ending March 2019, is approximately one dollar less than the price used for the 2014 price re-opener.
WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement using a base price that includes price escalators and quality adjustments through June 30, 2038 and includes actual cost per ton plus a margin equal to the yield for Moody’s A-Rated 10-Year CorporateUtility Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. The agreement stipulates that WRDC will supply coal to the 90 MW Wygen I plant through June 30, 2038.
Competition. Our primary strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically, any off-site sales have been to consumers within a close proximity to the WRDC mine. Rail transport market opportunities for WRDC coal are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC coal mine is served by only one railroad, resulting in less competitive transportation rates. Management continues to explore the limited market opportunities for our product through truck transport.
Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental considerations and availability affect the overall demand for coal as a fuel.
Environmental Matters. We are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. See Environmental Matters section for further information.
Mine Reclamation. Reclamation is required during production and after mining has been completed. Under applicable law, we must submit applications to, and receive approval from, the WDEQ for any mining and reclamation planplans that providesprovide for orderly mining, reclamation and restoration of the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC coal mine is permitted to operate under a five-year mining permit issued by the State of Wyoming. In 2016, that five-year permit was re-issued. Based on extensive reclamation studies, we have accrued approximately $16$14 million for reclamation costs as of December 31, 2018. Mining regulatory requirements continue2019. See additional information in Note 8 of the Notes to increase, which impose additional costthe Consolidated Financial Statements in this Annual Report on the mining process.Form 10-K.
Environmental Matters
South Dakota and Wyoming Power Generation. Based on current regulations, technology and plans, the following table contains our current estimates of capital expenditures expected to be incurred over the next three years to comply with current environmental laws and regulations as described below, including regulations that cover water, air, soil and other pollutants, but excluding plant closures and the cost of new generation. The ultimate cost could be significantly different from the amounts estimated.
|
| | | |
| Environmental Expenditure Estimates | Total (in thousands) |
| 2019 | $ | 1,503 |
|
| 2020 | 1,088 |
|
| 2021 | 710 |
|
| Total | $ | 3,301 |
|
Methane Rules (Greenhouse Gas Emissions). The EPA and the State of Colorado have implemented strict regulatory requirements on hydrocarbon and methane emissions associated with natural gas gathering and transmission systems. The BLM repealed similar hydrocarbon and methane emissions reductions it previously established under the Methane Rule (Venting and Flaring rule). Presently, we have four facilities in our Colorado natural gas transmission operations affected by the hydrocarbon and methane reduction rules.
Our operations are currently in compliance with both EPA and State of Colorado rules. Future modifications to our gathering and transmissions systems are anticipated to trigger EPA methane rules. We plan to develop a corporate-wide methane control strategy to address GHG emissions from our natural gas operations as we anticipate this will be a requirement in future rule-making efforts.
Water Issues. Our facilities are subject to a variety of state and federal regulations governing existing and potential water/ wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through EPA’s surface water discharge and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013, and published the final rule on November 3, 2015. In 2017, the EPA postponed the implementation of the rule and set a timeline in 2018 to revise the rule. To date, the rule has not been sent for publication.is being reviewed by the Office of Management and Budget. This rule will have an impact on the Wyodak Plant. Until the EPA issues the rule for publication, we can notcannot quantify what the potential impact may be on the Wyodak Plant. The terms of this new regulation may impact the next permit renewal, which will be in 2020.
Short-term Emission Limits. The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for SO2, NOx and Opacity.opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.
We proactively manage this requirement through maintenance efforts and installing additional pollution control systems to control SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut the power plant down if a predicted emission limit is to be exceeded. Similar efforts have been taken and similar results achieved with our natural gas fired combustion turbine sites as well.
Regional Haze (Impacts to the Wyodak Power Plant). The EPA Regional Haze rule was promulgated to improve visibility in our National Parks and Wilderness Areas.The State of Wyoming proposed controls in its Regional Haze State Implementation Plan (SIP) which allowed PacifiCorp to install low-NOx burners in the Wyodak Plant, of which South Dakota Electric owns 20%. The EPA did not agree with the State of Wyoming’s determination and overruled it in a Federal Implementation Plan (FIP). The State of Wyoming and other interested parties are challenging the EPA’s determination. If the challenge is unsuccessful, additional capital investment would be necessary to bring the Wyodak Plant into compliance. OurSouth Dakota Electric’s 20% share of this capital investment for the facility would be approximately $40$27 million if PacifiCorp is required to install a SelectiveSelective Catalytic Reactor for NOxcontrol. The case is currently held in abeyance at the 10th10th circuit court whileas the parties work on a settlement reached between onesettlement. Basin Electric, who is part of the interested parties andlegal action, settled with the EPA. In lieu of going to court, PacifiCorp entered into mediation with the EPA and conservation groups. PacifiCorp submitted a “Request for Reconsideration” on October 24, 2019 to the EPA and provided a copy to the court. The purpose of the submittal is implemented. to revisit the emission impacts and cost of additional investment.
Mining. Operations at the WRDC mine must regularly address issues related to the proximity of the mine disturbance boundary to the City of Gillette and to residential and industrial properties. Homeowner complaints and challenges to the permits may occur as mining operations move closer to residential areas. Specific concerns could include damage to wells, fugitive dust emissions, vibration and an emissions cloud from blasting.
Former Manufactured Gas Plants (FMGP). Federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. Our Gas Utilities are managing FMGP sites in Iowa and Nebraska. We are currently in discussions with the EPA, state regulators, and/or other third-parties to determine the ultimate resolution to these sites. As of December 31, 2018, we2019, our Gas Utilities have two active FMGP sites, which are working on the sitelocated in Council Bluffs, Iowa, and McCook, Nebraska. For the Council Bluffs site, the delay in clean-up is due to identifying the Potential Responsible Parties (PRPs or Successors to the Operators) to pay for the clean-up. We are the landowner and not the Successors to the Operator, whom would be responsible for paying for the majority of clean-up. We have been working with the EPA to identify the PRPs. The EPA has sent out information requests to the PRPs seeking transaction documents to determine the Successors to the Operators of the site inwho created the contamination. For the McCook, Nebraska. WeNebraska site, we have been contacted by a third-party who indicated it intends to manage and pay for the clean-up at this site. The third-party is conducting site assessments and working with the McCookState of Nebraska site.on a clean-up plan.
Affordable Clean Energy Rule. The EPA was directed to repeal, revise, and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy rule. This rule focuses on heat-rate improvements on coal-fired boiler unitsunits. In July 2019, the rule was finalized and poses significantly less risk thanapplies only to our coal-fired plants. These plants have implemented or plan to implement a majority of the Clean Power Plan. The 60-day comment period has ended andefficiency requirements listed in the EPA is reviewing comments prior to issuing a final rule.
OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR which is currently effective and establishes requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because coal ash is used for backfill reclamation in the areas previously mined. The current administration has not pursued further modification of the CCR.
Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 19 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Other Properties
In addition to the facilities previously disclosed in Items 1 and 2, we own or lease several facilities throughout our service territories. Our owned facilities are as follows:
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,Colorado, Iowa, Colorado, Kansas, Nebraska, and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 805,0001,030,000 square feet utilized by our Gas Utilities.
In Colorado, South Dakota, Wyoming, Colorado and MontanaWyoming we own various office, service center, storage, shop and warehouse space totaling approximately 240,000305,000 square feet utilized by our Electric Utilities and Mining segments.
In addition to our owned properties, we lease 194,36192,527 square feet of properties within our service areas.
Substantially all of the tangible utility properties of South Dakota Electric and Wyoming Electric are subject to liens securing first mortgage bonds issued by South Dakota Electric and Wyoming Electric, respectively.
Employees
At December 31, 20182019, we had 2,863 full-time employees in continuing operations.2,944 employees. Approximately 25% of our employees are represented by a collective bargaining agreement.union. We have not experienced any labor stoppages in recent years. At December 31, 20182019, approximately 23%22% of our total employees and 18%25% of our Electric and Gas Utilities employees were eligible for regular (age 65 with at least 5 years of service) or early (ages 55 to 64 with at least 5 years of service) retirement.
The following table sets forth the number of employees included in continuing operations:
|
| | |
| | Number of Employees |
Corporate | 499At December 31, 2019 |
| Corporate and Shared Services |
1,273 |
|
| Electric Utilities and Gas Utilities | 2,3011,609 |
|
MiningPower Generation and Power GenerationMining | 6362 |
|
| Total | 2,8632,944 |
|
At December 31, 20182019, certain employees of our Electric Utilities and Gas Utilities were covered by the following collective bargaining agreements:
|
| | | | |
| 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 | 103102 |
| IBEW Local 667 | April 15, 2023 |
| South Dakota Electric | 135 |
| IBEW Local 1250 | March 31, 2024 |
| Wyoming Electric | 23 |
| IBEW Local 111 | June 30, 2024 |
| Iowa Gas | 106113 |
| IBEW Local 204 | July 31, 2020 |
| Kansas Gas | 1918 |
| Communications Workers of America, AFL-CIO Local 6407 | December 31, 20192024 |
| Nebraska Gas | 99 |
| IBEW Local 244 | March 13, 2022 |
Nebraska Gas (a) | 146 |
| CWA Local 7476 | October 30, 2019 |
Wyoming Gas (a) | 85101 |
| CWA Local 7476 | October 30, 2019 |
| Total | 728737 |
| | |
__________
| |
| (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. There are ongoing negotiations with both bargaining units at this time. |
OPERATING RISKS
The nature of our business subjects us to a number of uncertainties and risks. The followingRisks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risk factors and other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company. These important factors
Our continued success is dependent on execution of our strategic business plans and other matters discussed hereingrowth strategy.
Our results of operations depend, in significant part, on our ability to execute our strategic business plans and growth strategy. Technology advancements, disruptive forces and innovations in the marketplace and changing business or regulatory conditions may negatively impact our current plans and strategies. An inability to successfully and timely adapt to changing conditions and execute our strategic plans and growth strategy could causematerially affect our future actualfinancial operating results or outcomes to differ materially.including earnings, cash flow and liquidity.
OPERATING RISKSWe may be subject to unfavorable federal and state regulatory outcomes.
Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and eight state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our various regulatory authorities will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in full recovery of our costs and the allowed return on invested capital. In addition, rate decisions could be influenced by many factors, including general economic conditions and the political environment.
Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and the state utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect financial operating results including earnings, cash flow and liquidity.
We may be subject to future laws, regulations, or actions associated with fossil-fuel generation and GHG emissions.
We own and operate regulated and unregulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase and deliver natural gas to our customers. These business activities are subject to evolving public concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.
Increased rules and regulations associated with fossil fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution, generation and storage facilities or coal mine. Further, these rules could create the need to purchase or build clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity.
Our financial performance depends on the successful operationmanagement of our facilities. If the risks involved in ourfacilities operations, are not appropriately managed or mitigated, our operations may not be successfulincluding ongoing operation, construction, expansion, and this could adversely affect our resultsrefurbishment.
Operation, construction, expansion and refurbishment of operations.
Operating electric generating facilities, the coal mine and electric and natural gas transmission and distribution systems, involvesnatural gas storage facilities, and a coal mine involve risks including:that could result in fires, explosions, property damage and personal injury, including death. These risks include:
Inherent dangers. Electricity and natural gas are dangerous for employees and the general public; contact with power lines, natural gas pipelines, electrical or natural gas service facilities and equipment can result in fires and explosions, causing significant property damage and personal injuries, including death;
Weather, natural conditions and disasters. Severe weather events could negatively impact operations, including our ability to provide energy safely and reliably and our ability to complete construction, expansion or refurbishment of facilities as planned. Extreme natural conditions and other disasters such as wind, lightning, flooding and winter storms, can cause wildfires, electric transmission or distribution pole failures, natural gas pipeline interruptions, outages, property damage and personal injury;
Operating hazards. Operating hazards such as leaks, mechanical problems and accidents, including fires or explosions could impact employee and public safety, reliability and customer confidence;
Labor and labor relations. The cost of recruiting and retaining skilled technical labor or the unavailability of such resources could have a negative impact on our operations. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2019, approximately 25% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk; approximately 25% of our employees are represented by a total of eight collective bargaining agreements.
Equipment and processes. Breakdown or failure of equipment or processes, the unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology.
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 toNatural gas supply of fuel and other commodities used infor generation and distribution. Our utilities purchase fuelnatural gas from a number of suppliers.suppliers for our generating facilities and for distribution to our customers. Our results of operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of fuelnatural gas 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 employeesReplacement power. The cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities could negatively impact our results of operations;
Governmental permits. The inability to obtain required governmental permits and approvals along with the general public should they come in contactcost of complying with power lines or electrical service facilitiessatisfying conditions imposed upon such approvals could negatively impact our ability to operate 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;our results of operations;
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. Operational limitations imposed by environmental and other regulatory requirements;
Breakdown or failure of equipment or processes,requirements and contractual agreements, including those operatedthat restrict the timing of generation plant scheduled outages, could negatively impact our results of operations;
Increased costs. Increased capital and operating costs to comply with increasingly stringent environmental and pipeline safety laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;
Public opposition. Opposition by PacifiCorp at the Wyodak Plant;
Labor relations. Approximately 25%members of public or special-interest groups could negatively impact our employees are represented by a total of eight collective bargaining agreements;
Our ability to transition and replaceoperate 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;businesses.
Inability to recruit and retain skilled technical labor; and
Disruption in the functioning of our information technology and network infrastructure which areis 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.
Changes in the interpretation of the Tax Cuts and Jobs Act (“TCJA”) could adversely affect us.
On December 22, 2017, the TCJA was signed into law, significantly reforming the U.S. Internal Revenue Code. The TCJA, among other things, includes a decrease in the U.S. federal corporate tax rate from 35% to 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, and modifies or repeals many business deductions and credits. The new tax law contains several provisions that impacted our 2017 and 2018 financial results.
The TCJA includes provisions limiting interest deductibility in certain circumstances. While we expect to maintain deductibility of interest expense, the lower tax rate reduces the tax benefits associated with interest deductibility on holding company debt that is not recovered in the regulatory construct.
If there are future changes and amendments to the TCJA, and if we are unable to obtain reasonable outcomes with our utility regulators in passing future benefits of the TCJA back to customers, or if our interpretations on the provisions of depreciation or interest deductibility in the TCJA change, our results of operations, financial position or cash flows could be materially impacted.
Construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve significant risks which could reduce profitability.
The construction, expansion, refurbishment and operation of power generating and transmission and resource extraction facilities involve many risks, including:
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.
The ongoing operation of our facilitiesbusiness involves many of the risks described above, in addition to risks relatingassociated with threats to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology.our overall business model, such as electrification initiatives. Any of these risks could cause us to experience negative financial results and damage to our reputation and public confidence. These risks could cause us to incur significant costs or be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce revenues increase expenses or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance and obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.
Our energy production, transmission and distribution activities, and our storage facilities for our natural gas involve numerous risks that may result in accidents and other catastrophic events.
Inherent in our businesses are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. Many of our transmission and distribution assets are located near populated residential areas, commercial business centers and industrial sites.
These hazards could result in injury or loss of human life, cause environmental pollution, significantly damage property or natural resources or impair our ability to operate our facilities. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully covered by our insurance and could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.
OperatingCustomer growth and usage in our service territories may fluctuate with current economic conditions, emerging technologies or responses to price increases.
Our financial operating results canare impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, economic conditions impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our financial operating results including earnings, cash flow and liquidity.
Cyberattacks, terrorism, or other malicious acts could disrupt our operations, or lead to a loss or misuse of confidential and proprietary information.
To effectively operate our business, we rely upon a sophisticated electronic control system, SCADA, information technology systems and network infrastructure to collect and retain sensitive information including personal information about our customers and employees. Cyberattacks, terrorism or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or gas operations. Attacks targeting other key information technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.
We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective. Despite our implementation of security measures and safeguards, all of our information technology systems may be vulnerable to disability, failures or unauthorized access
Risks associated with deployment of capital may impact our ability to execute our business plans and growth strategy.
We have significant capital investment programs planned for the next five years. The successful execution of our capital investment strategy depends on, or could be affected by, variations from normala variety of factors that include, but are not limited to: extreme weather conditions.conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, governmental approvals and permitting and regulatory cost recovery.
Weather conditions may cause fluctuation in customer usage as well as service disruptions.
Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation. Unusually mild summers and winters, therefore, could have an adverse effect on our results of operations, financial position or cash flows.
Our businesses are located in areas that could be subject to seasonal natural disasterssevere weather events such as severe snow and ice storms, tornadoes, strong winds, significant thunderstorms, flooding and wildfires.drought. These events could result in interruption of our business,lost operating revenues due to outages, property damage, to our property such as powerincluding inoperable generation facilities and downed transmission and distribution lines, and substations, and repair and clean-up costs.storm restoration activities. We may not be able to recover the costs incurred in restoring transmission and distribution property following these natural disasters through a change in our regulated rates therebyweather events resulting in a negative impact on our financial operating results of operations, financial positionincluding earnings, cash flow and cash flows.liquidity.
Our Mining operations are subject to operating risks that are beyond our control which could affect our profitability and production levels. Our surface mining operations could be disrupted or materially affected due to adverse weather or natural disasters such as heavy snow, strong winds, rain or flooding.
Prices for some of our products and services as well as a portion of our operating costs are volatile and may cause our revenues and expenses to fluctuate significantly.
A portion of our net income is attributable to sales of wholesale and off-system electricity and natural gas. Energy prices are influenced by many factors outside our control, including, among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions, and the rules, regulations and actions of system operators in those markets. As a result, wholesale power marketsWe may be subject to significant, unpredictable price fluctuations over relatively short periods of time.
Our Mining operations require reliable supply of replacement parts, explosives, fuel, tires and steel-related products. If the cost of these increase significantly, or if sources of supplies and mining equipment become unavailable to meet our replacement demands, our productivity and profitability could be lower than our current expectations.
Our revenues, results of operations and financial condition are impacted by customer growth and usage in our service territories and may fluctuate with current economic conditions, emerging technologies or responses to price increases.
Our revenues, results of operations and financial condition are impacted by demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction of consumption of electricity and natural gas by our customers in response to increases in prices and demand-side management programs, economic conditions impacting decreases in customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our results of operations, financial position or cash flows.
Our operations rely on storage and transportation assets owned by third parties to satisfy our obligations.
Our Electric Utilities, Gas Utilities and Power Generation segments rely on pipeline companies and other owners of gas storage facilities to deliver natural gas to customers, to supply our natural gas-fired power plants and to hedge commodity costs. If storage capacity is inadequate or transportation is disrupted, our ability to satisfy our obligations may be hindered. As a result, we may be responsible for damages incurred by our counterparties, such as the additional cost of acquiring alternative supply at then-current market rates, or for penalties imposed by state regulatory authorities.
Our utilities are subject to pipeline safety and system integrity laws and regulations that may require significant capital expenditures or significant increases in operating costs.
Compliance with pipeline safety and system integrity laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers through rates. Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers through rates and could result in a material impact on our results of operations, financial position or cash flows.
Our energy production, transmission and distribution activities, and our storage facilities for our natural gas involve numerous risks that may result in accidents and other catastrophic events that could give rise to additional costs and cause a substantial loss to us.
Inherent in our natural gas and electricity transmission and distribution activities, as well as in our transportation and storage of natural gas and our Mining operations, are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. These events could impact the safety of employees or others and result in injury or loss of human life, and cause significant damage to property or natural resources (including public lands), environmental pollution, impairment of our operations and substantial financial losses to us. Particularly for our transmission and distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the damages resulting from any such events could be substantial. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events not fully covered by our insurance could have a material adverse effect on our financial position, results of operations or cash flows.
Threats of terrorism and catastrophic events that could result from terrorism, or individuals and/or groups attempting to disrupt our businesses, or the businesses of third parties, may impact our operations in unpredictable ways.
Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power, deliver natural gas and by delaying their development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels. They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.
The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our financial results. In addition, these types of events could require significant management attention and resources and could adversely affect our reputation among customers and the public.
A cyber attack may disrupt our operations, or lead to a loss or misuse of confidential and proprietary information and create a potential liability.
We use and operate sophisticated control, SCADA, and information technology systems and network infrastructure. In addition, in the ordinary course of business, we collect and retain sensitive information including personal information about our customers and employees. Cyber attacks targeting our electronic control systems used at our generating facilities and for electric and gas distribution systems, could result in a full or partial disruption of our electric and/or gas operations. Cyber attacks targeting other key information technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data as a result of a cyber attack could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.
We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective due to the evolving nature and sophistication of cyber attacks. Despite our implementation of security measures and safeguards, all of our information technology systems are vulnerable to disability, failures or unauthorized access, including cyber attacks. If our information technology systems or our third-party vendors’ systems were to fail or be breached by a cyber attack or a computer virus and be unable to recover in a timely way, we would be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised which could have a material adverse effect not only on our financial results, but on our public reputation as well.
Increased risks of regulatory penalties could negatively impact our results of operations, financial position or liquidity.penalties.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Agencies that historically sought voluntary compliance, or issued non-monetary sanctions, nowMany agencies employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, SEC and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business, which could have a material adverse effect on our operations and/or our financial results.operating results including earnings, cash flow and liquidity.
Certain Federal laws including the Migratory Bird Act and the Endangered Species Act, provide special protection to certain designated animal species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation, wind and pipeline projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.
Our current or future development and expansion activities may not be successful, which could impair our ability to execute our growth strategy.
Execution of our growth plan is dependent on successful ongoing and future development and expansion activities. We can provide no assurance that we will be able to complete development projects or expansion activities we undertake or continue to develop attractive opportunities for growth. Factors that could cause our development and expansion activities to be unsuccessful include:
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.
Utilities
Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and therefore are not recoverable.
Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our direct and allocated borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) without having to file a rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.
If market or other conditions adversely affect operations or require us to make changes to our business strategy in any of our utility businesses, we may be forced to record a non-cash goodwill impairment charge. Any significant impairment of our goodwill related to these utilities would cause a decrease in our assets and a reduction in our net income and shareholders’ equity.
We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2018. A substantial portion of the goodwill is related to the SourceGas Acquisition and the Aquila Transaction. If we make changes in our business strategy or if market or other conditions adversely affect operations in any of our businesses, we may be forced to record a non-cash impairment charge, which would reduce our reported assets, net income and shareholders’ equity. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes in economic conditions and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more business segments, which may result in an impairment charge.
Municipal governments may seek to limit or deny our franchise privileges which could inhibit our ability to secure adequate recovery of our investment in assets subject to condemnation.privileges.
Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. We regularly engage in negotiations on renewals of franchise agreements with our municipal governments. We have from time to time faced challenges or ballot initiatives on franchise renewals. To date, we have been successful in resolving or defending each of these challenges. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.
Mining
If We also cannot quantify the assumptions underlying our reclamation and mine closure obligations are materially inaccurate, our costs could be significantly greater than anticipated or be incurred sooner than anticipated.
We conduct surface mining operationsimpact that are subject to operations, reclamation and closure standards. We estimate our total reclamation liabilities basedsuch action would have on permit requirements, engineering studies and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers and by government regulators. The estimated liability can change significantly if actual costs vary from our original assumptions or if government regulations change significantly. GAAP requires that asset retirement obligations be recorded as a liability based on fair value, which reflects the present value of the estimated future cash flows. In estimating future cash flows, we consider the estimated current cost of reclamation and apply inflation rates. The resulting estimated reclamation obligations could change significantly if actual amounts or the timing of these expenses change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial position.
Estimates of the quality and quantityremainder of our coal reserves may change materially due to numerous uncertainties inherent in three-dimensional structural modeling, and any inaccuracies in interpretation or modeling could materially affect the estimated quantity and quality of our reserves.business operations.
The process of estimating coal reserves is uncertain and requires interpretations and modeling. Significant inaccuracies in interpretation or modeling could materially affect the quantity and quality of our reserve estimates. The accuracy of reserve estimates is a function of engineering and geological interpretation, conditions encountered during actual reserve recovery and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that require reserve revisions either upward or downward from prior reserve estimates.
FINANCING RISKS
OurA sub-investment grade credit ratings could be lowered below investment grade in the future. If this were to occur, itrating could impact our ability to access to capital cost of capital and other operating costs.markets.
Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new financings on reasonable terms, orif at all. A credit rating downgrade, particularly to a sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts or trades.contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities.facilities, potentially significantly increasing our cost of capital and other associated operating costs.
Derivatives regulations could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
Dodd-Frank contains significant derivatives regulations, including a requirement that certain transactions be cleared resulting in a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users such as utilities and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.
We use natural gas derivative instruments for our hedging activities for our Gas and Electric Utilities’ operations. We may also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral for certain swap transactions we enter into. In addition, our exchange-traded futures contracts are subject to futures margin posting requirements, which could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.
Our hedging activities that are designed to protect against commodity price and financial market risks may cause fluctuations in reported financial results due to mark-to-market accounting requirements associated with such activities.treatment.
We use various financial contracts and derivatives, including futures, forwards, options and swaps to manage commodity price and financial market risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities being hedged. The difference in accounting may result in volatility in reportedFluctuating commodity prices could have a negative effect on our liquidity, financial condition, and results even though the expected profit margin may be essentially unchanged from the dates the transactions were consummated.of operations.
Our use of derivative financial instruments could result in material financial losses.
From time to time, we have sought to limit a portion of the potential adverse effects resulting from changes in commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.
Market performance or changes in otherkey valuation assumptions could require us to make significant unplanned contributions to our pension plans and other postretirement benefit plans. Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or cash flows.
As discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan (the pension plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria) and several defined post-retirement healthcare plans and non-qualified retirement plans that cover certain eligible employees. Assumptions related to future costs,interest rates, expected return on investments, interest ratesmortality and other key actuarial
assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. These estimatesAn adverse change to key assumptions associated with our defined benefit retirement plans may require significant unplanned contributions to the plans which could adversely affect our financial operating results including earnings, cash flow and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations.liquidity.
We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments are dependent upon cash distributions to the holding company from the subsidiaries.
As a holding company, our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital, equity or debt service funds.
There is no assurance as to the amount, if any, of future dividends because they depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. Our operating subsidiaries have certain restrictions on their ability to transfer funds in the form of dividends or loans to us. See “Liquidity“Liquidity and Capital Resources”Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.
We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.
Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, pay dividends and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.
In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in the context of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.
National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts, which could adversely affect our results of operations, financial position or cash flows.accounts.
A future recession, if one occurs, may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.
Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage may not provide protection against all significant losses.
Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting insurance businesses, international, national, state or local events, as well as the financial condition of insurers. Insurance coverage may not continue to be available at all, or at rates or on terms similar to those presently available to us. A loss for which we are not fully insured could materially and adversely affect our financial results. Our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which the Company may be subject, including but not limited to environmental hazards, fire-related liability from natural events or inadequate facility maintenance, distribution property losses, cyber-security risks and dangers that exist in the gathering and transportation of gas in pipelines.
Increasing costsCosts associated with our healthcare plans and other benefits may adversely affect our results of operations, financial position or liquidity.could increase significantly.
The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have, and likely will continue to, require changes to our current employee benefit plans and in our administrative and accounting processes, as well as changes to the cost of our plans, and the increasing costs and funding requirements associated with our healthcare plans may adversely affect our results of operations, financial position or cash flows.
processes. Our electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there can be no assurance that the state public utility commissions will allow recovery. The increasing cost, or inadequate recovery of, rising employee benefit costs may adversely affect our financial operating results including earnings, cash flow, or liquidity.
An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the effectiveness of these controls. During their assessment of these controls, management or our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in a loss of investor confidence in our financial reports or have a material adverse effect on our ability to operate our business or access sources of liquidity.
A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. If we are unable to assert that our internal controls over financial reporting are effective, market perception of our business, operating results and stock price could be adversely affected.
ENVIRONMENTAL RISKS
Developments in federal and state laws concerning GHG regulations and air emissions relating to climate may adversely impact operations, financial results andcould materially increase our generation and production costs which couldand render some of our generating units uneconomical to operate and maintain.maintain.
To the extent climate change occurs, our businesses could be adversely impacted. We believe it is likely that any such resulting impacts would occur very gradually over a very long period of time and thus would be difficult to quantify. Warmer temperatures during the heating season in our natural gasutility service territories, or cooler temperatures during the cooling season in our electric service territories could adversely affect financial results through lower natural gas volumes delivered, lower MWh sold and associated lower revenues.
We own and operate regulated and non-regulated fossil-fuel generating plants in Colorado, South Dakota Wyoming and Colorado.Wyoming. Developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which could have a material impact on our costs of operations. Various pending or final state and EPA regulations that will impact our facilities are also discussed in Item 1 of this Annual Report on Form 10-K under the section “Environmental Matters”“Environmental Matters”.
DueThere is uncertainty surrounding current climate regulation due to uncertainty as to the final outcome oflegal challenges, new federal climate regulation, legal challenges,legislation anticipated in the future, or state CPP developments or regulatory changes under the Clean Air Act, weclimate legislation and regulation. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial position or cash flows.
New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or reduction of load of coal-fired power generation facilities and potential increased load of our combined cycle natural gas-fired generation units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants
from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.maintain; this could cause those generating units to be de-commissioned, potentially resulting in impairment costs. We will attempt to recover any remaining asset value; however, any unrecovered costs could have a material impact on our results of operations and financial condition.
The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, and anyor failure to do so,comply, could adversely affect our results of operations, financial position or liquidity.increase significantly.
Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.
The business segments may not be successful in recovering capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on the business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.
The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization and the use of alternative energy sources for power generation as mandated by states could reduce coal consumption.utilization.
Future regulations may require further reductions in emissions of mercury, hazardous pollutants, SO2, NOx, volatile organic compounds, particulate matter and GHG, which are released into the air when coal is burned. These requirements could require the installation of costly emission control technology or the implementation of other measures.
Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. The EPA was directed to repeal, revise and replace the CPP rule. At this time, it is not known what effect this will have on coal as a domestic energy source, and could have a significant impact on our mining operations.
Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our financial operating results of operations, financial position orincluding earnings, cash flowsflow and liquidity could be adversely impacted.
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| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 19, “Commitments and Contingencies”, of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
ITEM 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Annual Report.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
David R. Emery, age 57, has been Executive Chairman since January 1, 2019, Chairman and Chief Executive Officer from 2016 through 2018, and Chairman, President and Chief Executive Officer from 2005 through 2015. Prior to that, he held various positions with the Company, including President and Chief Executive Officer and member of the Board of Directors from 2004 to 2005, President and Chief Operating Officer — Retail Business Segment from 2003 to 2004 and Vice President — Fuel Resources from 1997 to 2003. Mr. Emery has 30 years of experience with the Company.
Linden R. Evans, age 57, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer — Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 18 years of experience with the Company.
Scott A. Buchholz, age 58, has been our Senior Vice President — Chief Information Officer since the closing of the Aquila Transaction in 2008. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 39 years of experience with the Company, including 28 years with Aquila.
Brian G. Iverson, age 57, has been Senior Vice President, General Counsel and Chief Compliance Officer since August 26, 2019. He served as Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary from February 1, 2019 to August 26, 2019, Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 16 years of experience with the Company.
Richard W. Kinzley, age 54, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 20 years of experience with the Company.
Jennifer C. Landis, age 45, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 18 years of experience with the Company.
Karen Beachy, age 48, has been Senior Vice President - Growth and Strategy since August 26, 2019. She served as Vice President - Growth and Strategy from 2018 to August 2019, Vice President - Supply Chain from 2016 to 2018, and Director of Supply Chain from 2014 to 2016. Ms. Beachy has 5 years of experience with the Company.
Stuart Wevik, age 58, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 34 years of experience with the Company.
PART II
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| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of December 31, 20182019, we had 3,6893,586 common shareholders of record and approximately 41,00032,285 beneficial owners, representing all 50 states, the District of Columbia and 76 foreign countries.
We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 30, 201929, 2020 meeting, our Board of Directors declared a quarterly dividend of $0.505$0.535 per share, equivalent to an annual dividend rate of $2.02$2.14 per share. The 2019This equivalent rate, if declared and paid in 2020, will represent 50 consecutive years of $2.02 per share would mark 2019 as the 49th consecutive annual dividend increase for the Company.increases.
For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity“Liquidity and Capital Resources”Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
UNREGISTERED SECURITIES ISSUED
There were no unregistered securities sold during 2018.2019.
ISSUER PURCHASES OF EQUITY SECURITIES
|
| | | | |
There were no equity securities acquired for the twelve months ended December 31, 2018.2019. |
| |
| ITEM 6. | SELECTED FINANCIAL DATA |
(Minor differences may result due to rounding)
| | | Years Ended December 31, | 2018 | | 2017 | | 2016 | | 2015 | | 2014 | 2019 | | 2018 | | 2017 | | 2016 (a) | | 2015 | |
| (dollars in thousands, except per share amounts) | (dollars in thousands, except per share amounts) | | | | | | | | | (dollars in thousands, except per share amounts) | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | $ | 6,963,327 |
| | $ | 6,658,902 |
| | $ | 6,541,773 |
| | $ | 4,626,643 |
| | $ | 4,216,752 |
| $ | 7,558,457 |
| | $ | 6,963,327 |
| | $ | 6,658,902 |
| | $ | 6,541,773 |
| | $ | 4,626,643 |
| |
| | | | | | | | | | | | | | | | | | | | |
Property, Plant and Equipment | | | | | | | | | | | | | | | | | | | |
| Total property, plant and equipment | $ | 6,000,015 |
| | $ | 5,567,518 |
| | $ | 5,315,296 |
| | $ | 3,849,309 |
| | $ | 3,606,931 |
| |
| Property, plant and equipment | | $ | 6,784,679 |
| | $ | 6,000,015 |
| | $ | 5,567,518 |
| | $ | 5,315,296 |
| | $ | 3,849,309 |
| |
| Accumulated depreciation and depletion | (1,145,136 | ) | | (1,026,088 | ) | | (929,119 | ) | | (794,695 | ) | | (714,762 | ) | (1,281,493 | ) | | (1,145,136 | ) | | (1,026,088 | ) | | (929,119 | ) | | (794,695 | ) | |
| Total property, plant and equipment, net | $ | 4,854,879 |
| | $ | 4,541,430 |
| | $ | 4,386,177 |
| | $ | 3,054,614 |
| | $ | 2,892,169 |
| $ | 5,503,186 |
| | $ | 4,854,879 |
| | $ | 4,541,430 |
| | $ | 4,386,177 |
| | $ | 3,054,614 |
| |
| | | | | | | | | | | | | | | | | | | | |
| Capital Expenditures | | | | | | | | | | | | | | | | | | | |
| Continuing Operations | $ | 502,424 |
| | $ | 337,689 |
| | $ | 460,450 |
| | $ | 289,896 |
| | $ | 281,828 |
| $ | 849,755 |
| | $ | 502,424 |
| | $ | 337,689 |
| | $ | 460,450 |
| | $ | 289,896 |
| |
Discontinued Operations | 2,402 |
| | 23,222 |
| | 6,669 |
| | 168,925 |
| | 109,439 |
| — |
| | 2,402 |
| | 23,222 |
| | 6,669 |
| | 168,925 |
| |
| Total Capital Expenditures | $ | 504,826 |
| | $ | 360,911 |
| | $ | 467,119 |
| | $ | 458,821 |
| | $ | 391,267 |
| $ | 849,755 |
| | $ | 504,826 |
| | $ | 360,911 |
| | $ | 467,119 |
| | $ | 458,821 |
| |
| | | | | | | | | | | | | | | | | | | | |
Capitalization (excluding noncontrolling interests) | | | | | | | | | | | | | | | | | | | |
| Current maturities of long-term debt | $ | 5,743 |
| | $ | 5,743 |
| | $ | 5,743 |
| | $ | — |
| | $ | 275,000 |
| $ | 5,743 |
| | $ | 5,743 |
| | $ | 5,743 |
| | $ | 5,743 |
| | $ | — |
| |
| Notes payable | 185,620 |
| | 211,300 |
| | 96,600 |
| | 76,800 |
| | 75,000 |
| 349,500 |
| | 185,620 |
| | 211,300 |
| | 96,600 |
| | 76,800 |
| |
| 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 |
| |
| Long-term debt, net of current maturities | | 3,140,096 |
| | 2,950,835 |
| | 3,109,400 |
| | 3,211,189 |
| | 1,853,682 |
| |
| Total stockholders’ equity | | 2,362,123 |
| | 2,181,588 |
| | 1,708,974 |
| | 1,614,639 |
| | 1,465,867 |
| |
| Total capitalization | $ | 5,323,786 |
| | $ | 5,035,417 |
| | $ | 4,928,171 |
| | $ | 3,396,349 |
| | $ | 2,959,837 |
| $ | 5,857,462 |
| | $ | 5,323,786 |
| | $ | 5,035,417 |
| | $ | 4,928,171 |
| | $ | 3,396,349 |
| |
| | | | | | | | | | | |
| 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 |
| $ | 1,734,900 |
| | $ | 1,754,268 |
| | $ | 1,680,266 |
| | $ | 1,538,916 |
| | $ | 1,261,322 |
| |
| | | | | | | | | | | | | | | | | | | | |
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 |
| |
| Net Income Available for Common Stock | | Net Income Available for Common Stock | | | | | | | | | |
| Income from continuing operations available for common stock | | 199,310 |
| (c) (g) | 265,329 |
| (c)(f) | 194,133 |
| (c) (d) | 137,132 |
| (c) (d) | 141,548 |
| (d) |
Income (loss) from discontinued operations, net of tax (b) | (6,887 | ) | | (17,099 | ) | | (64,162 | ) | | (173,659 | ) | | (1,573 | ) | — |
| | (6,887 | ) | | (17,099 | ) | | (64,162 | ) | | (173,659 | ) | |
| Net income (loss) available for common stock | $ | 258,442 |
| | $ | 177,034 |
| | $ | 72,970 |
| | $ | (32,111 | ) | | $ | 130,889 |
| $ | 199,310 |
| | $ | 258,442 |
| | $ | 177,034 |
| | $ | 72,970 |
| | $ | (32,111 | ) | |
| | | | | | | | | | | | |
Common Stock Data(e) (in thousands) | | | | | | | | | | | |
| Shares outstanding, average basic | | 60,662 |
| | 54,420 |
| | 53,221 |
| | 51,922 |
| | 45,288 |
| |
| Shares outstanding, average diluted | | 60,798 |
| | 55,486 |
| | 55,120 |
| | 53,271 |
| | 45,288 |
| |
| Shares outstanding, end of year | | 61,477 |
| | 60,004 |
| | 53,541 |
| | 53,382 |
| | 51,192 |
| |
SELECTED FINANCIAL DATA continued
| | | Years Ended December 31, | 2018 | | 2017 | | 2016 | | 2015 | | 2014 | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 | |
| (dollars in thousands, except per share amounts) | (dollars in thousands, except per share amounts) | | | | | | | | | | (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) | Earnings (Loss) Per Share of Common Stock (in dollars) | | | | | | | | | 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 |
| | $ | 3.52 |
| | $ | 5.14 |
| | $ | 3.92 |
| | $ | 2.83 |
| | $ | 3.12 |
| |
Discontinued operations (b) | (0.13 | ) | | (0.32 | ) | | (1.23 | ) | | (3.83 | ) | | (0.04 | ) | | — |
| | (0.13 | ) | | (0.32 | ) | | (1.23 | ) | | (3.83 | ) | |
| Non-controlling interest | (0.26 | ) | | (0.27 | ) | | (0.19 | ) | | — |
| | — |
| | |
Non-controlling interest (c) | | (0.23 | ) | | (0.26 | ) | | (0.27 | ) | | (0.19 | ) | | — |
| |
| Total | $ | 4.75 |
| | $ | 3.33 |
| | $ | 1.41 |
| | $ | (0.71 | ) | | $ | 2.94 |
| | $ | 3.29 |
| | $ | 4.75 |
| | $ | 3.33 |
| | $ | 1.41 |
| | $ | (0.71 | ) | |
| Diluted earnings (loss) per average share - | Diluted earnings (loss) per average share - | | | | | | | | | | Diluted earnings (loss) per average share - | | | | | | | | | |
| Continuing operations | $ | 5.04 |
| | $ | 3.78 |
| | $ | 2.75 |
| | $ | 3.12 |
| | $ | 2.97 |
| | $ | 3.51 |
| | $ | 5.04 |
| | $ | 3.78 |
| | $ | 2.75 |
| | $ | 3.12 |
| |
Discontinued operations (b) | (0.12 | ) | | (0.31 | ) | | (1.20 | ) | | (3.83 | ) | | (0.04 | ) | | — |
| | (0.12 | ) | | (0.31 | ) | | (1.20 | ) | | (3.83 | ) | |
| Non-controlling interest | (0.26 | ) | | (0.26 | ) | | (0.18 | ) | | — |
| | — |
| | |
Non-controlling interest (c) | | (0.23 | ) | | (0.26 | ) | | (0.26 | ) | | (0.18 | ) | | — |
| |
| Total | $ | 4.66 |
| | $ | 3.21 |
| | $ | 1.37 |
| | $ | (0.71 | ) | | $ | 2.93 |
| | $ | 3.28 |
| | $ | 4.66 |
| | $ | 3.21 |
| | $ | 1.37 |
| | $ | (0.71 | ) | |
| | | | | | | | | | | | |
| Cash Dividends Paid on Common Stock | | $ | 124,647 |
| | $ | 106,591 |
| | $ | 96,744 |
| | $ | 87,570 |
| | $ | 72,604 |
| |
| | | | | | | | | | | | | | | | | | | | | |
| Dividends Declared per Share | $ | 1.93 |
| | $ | 1.81 |
| | $ | 1.68 |
| | $ | 1.62 |
| | $ | 1.56 |
| | $ | 2.05 |
| | $ | 1.93 |
| | $ | 1.81 |
| | $ | 1.68 |
| | $ | 1.62 |
| |
| | | | | | | | | | | | | | | | | | | | | |
| Book Value Per Share, End of Year | $ | 36.36 |
| | $ | 31.92 |
| | $ | 30.25 |
| | $ | 28.63 |
| | $ | 30.31 |
| | $ | 38.42 |
| | $ | 36.36 |
| | $ | 31.92 |
| | $ | 30.25 |
| | $ | 28.63 |
| |
| | | | | | | | | | | | |
Return on Average Equity (f) | 13.6 | % | | 11.7 | % | | 8.9 | % | | 10.0 | % | | 10.0 | % | | |
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| (a) | The increase inEffective February 12, 2016, includes the debt associated withwe completed the SourceGas acquisition (see Note 6Transaction. Total cash consideration paid, net of debt assumed and working capital adjustment received, was $1.124 billion, funded with a combination of the Notes toissuance of 6.3 million shares of our common stock on November 23, 2015, 5.98 million equity units issued on November 23, 2015, $546 million of net proceeds from the Consolidated Financial Statements in this Annual Reportissuance of senior unsecured notes on Form 10-K).January 13, 2016, cash on hand and draws under our revolving credit facility. |
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| (b) | On November 1, 2017, we made the decision to divest our Oil and Gas assets.assets which was completed in 2018. Oil and Gas results are shown in discontinued operations. 2017 includes ana non-cash 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).million. |
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| (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 2019, 2018, 2017 and 2016 was reduced by $14 million, $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest. |
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| (d) | 2017, 2016 and 2015 include incremental SourceGas AcquisitionTransaction 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. |
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| (e) | In 2019, we issued 1.33 million shares at an average share price of $75.28 under our ATM equity offering program. 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. |
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| (f) | Calculated based on Net income (loss) from continuing operations available for common stock. |
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(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. |
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(h)(g) | 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, 20172019 includes a net tax benefitnon-cash after-tax impairment of $7.6$15 million fromin our investment in equity securities of a privately held oil and gas company. See Note 1 of the revaluation of deferred tax balances dueNotes to a decreasethe Consolidated Financial Statements in the statutory Federal income tax rate resulting from the TCJA. The (expense) benefit impact to our operating segments and Corporate and Otherthis Annual Report on Form 10-K 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.more information. |
For additional information on our business segments see Item 7.7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures about Market Risk and Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
ITEMS 7 & and 7A. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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ITEMS Items 7 & | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS |
| and 7A Index |
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| OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET |
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RISK
Executive Summary
We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of improving life with energy and a vision to be the energy partner of choice. The Company provides electricity and natural gas through its Electric Utilities and Gas Utilities to 1.271.3 million customers in 823824 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company’s Electric Utilities are supported by our Power Generation and Mining segments. The Power Generation segment produces electric power from its threefive generating plantsfacilities and sells most of the electric capacity and energy principally to our Electric Utilities under long-term contracts. Our Mining segment produces coal at our mineonly location near Gillette, Wyoming, and sells the coal primarilynearly all production to fuel the on-site, mine-mouth power generation facilities.
The Company has provided energy and served customers for 135136 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. Our strategic focus has not changed in over a century - serving customers with affordable, reliable and safe energy. Our strategy today continues that emphasis on serving customers, but with a renewed focus on better engaging with the people and communities we serve. Customer expectations are rapidly changing with the advancement of technology and customers are demanding simpler, faster and more convenient solutions to their energy needs. We are readyReady to serve as we have done for the past 135136 years.
Our strategy consists of five primary areas that focus on improving the way we serve customers with safe, reliable and affordable energy while improving the lives of the customers and communities we serve. The strategy is to 1) modernize utility infrastructure 2) pursue operating efficiencies 3) transform the customer experience 4) add renewable generation to meet customer demand and 5) become the safest energy company in the utility industry.industry; 2) transform the customer experience; 3) grow our electric and natural gas customer load; 4) pursue operating efficiencies; and 5) modernize utility infrastructure. This strategic focus will present the company with significant investment opportunities over the next several yearsneeds as we modernize our infrastructure systems and meet customer growth. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective interactions.
Key Elements of our Business Strategy
Replace, modernizeModernize, replace and operate utility infrastructure to meet our customer’scustomers’ energy needs bywhile providing safe, reliable and reliableaffordable energy. Our utilities own and operate large electric and natural gas infrastructure systems that span nearly 1,600 miles, reaching from Cody, Wyoming to Blytheville, Arkansas.miles. Our Gas Utilities own and operate 45,000 miles of natural gas transmission and distribution pipelines and our Electric Utilities own and operate 939 MW of generation capacity and 8,8008,900 miles of transmission and distribution lines.lines and our Gas Utilities own and operate 46,000 miles of natural gas transmission and distribution pipelines. A key strategic focus is to modernize this utility infrastructure to meet customerscustomers’ and communities’ varied energy needs and to ensure the continued delivery of safe, reliable and reliableaffordable energy. In addition, we need to invest in the accessibility, capacity and integrity of our systems to meet customer growth. An overriding strategic focus in
We rigorously comply with all that we do isapplicable federal, state and local regulations and strive to ensure the safe delivery of energy to our customers and communities, particularly in light of recentconsistently meet industry pipeline accidents.
best practice standards. A key component of our modernization effort is the development of programs by our Electric and Gas utilities to systematically and proactively replace aging infrastructure on a system-wide basis. To support its safetymeet our electric customers’ continued expectations of high levels of reliability, our Electric Utilities utilize a distribution integrity program to ensure the timely repair and reliability focus, ourreplacement of aging infrastructure. Our Gas Utilities have developedutilize a programmatic approach to system-wide pipeline system replacement, particularly in high consequence areas. Under the programmatic approach, obsolete, at-risk and vintage materials will beare replaced in a proactive and systematic time frame. To meet our electric customers’ continued expectations of high levels of reliability, our Electric Utilities are developing a distribution integrity program to ensure the timely repair and replacement of an aging infrastructure system.
We estimate our five-year capital investment to be approximately $2.5 billion, with most of that investment targeted toward replacing existing utility infrastructure and to meet customer growth. Our actual 2018 and estimated capital expenditures for next five years from 2019 through 2023 are as follows (in millions):
|
| | | | | | | | | | | | | | | | | | |
| | 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 |
|
(a) 2018 includes the $7.6 million Busch Ranch 1 Wind Farm contract intangible asset. See Note 4, “Jointly Owned Facilities”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.
Maintain a safe and reliable gas distribution system.We rigorously comply with all applicable federal, state and local regulations and strive to consistently meet industry best practice standards. Preventing natural gas losses from our gas delivery systems is of the utmost importance to ensure public and employee safety and to protect the environment. We construct, maintain and update our gas delivery systems with state of the art materials and products and continuously monitor their integrity. System leaks are repaired as soon as possible while focusing on the safety of the public and our employees. We have removed all castcast- and wrought ironwrought-iron from our natural gas transmission and distribution systems and continue to replace aging infrastructure through programs that prioritize safety and reliability for our customers. Many of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments which reflect the cost incurred in repairing and replacing the gas delivery systems.
We estimate our five-year capital investment to be approximately $2.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure and to support customer and community growth needs. Our actual 2019 and forecasted capital expenditures and depreciation for next five years from 2020 through 2024 are as follows (in millions):
|
| | | | | | | | | | | | | | | | | | |
| | Actual | Planned | Planned | Planned | Planned | Planned |
| Capital Expenditures By Segment | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 |
| (in millions) | | | | | | |
| Electric Utilities | $ | 223 |
| $ | 246 |
| $ | 203 |
| $ | 170 |
| $ | 137 |
| $ | 152 |
|
| Gas Utilities | 512 |
| 391 |
| 309 |
| 285 |
| 316 |
| 293 |
|
| Power Generation | 85 |
| 7 |
| 9 |
| 11 |
| 6 |
| 6 |
|
| Mining | 9 |
| 8 |
| 12 |
| 9 |
| 9 |
| 9 |
|
| Corporate and Other | 21 |
| 17 |
| 22 |
| 11 |
| 12 |
| 10 |
|
| Total | $ | 850 |
| $ | 669 |
| $ | 555 |
| $ | 486 |
| $ | 480 |
| $ | 470 |
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Efficiently plan, construct and operate rate base power generation facilities to serve our Electric Utilities. We believe that we best serve customers and communities with a vertically integrated business model for our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to cost-effectively supply electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.
Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low-powerlow power production costs result from a variety of factors including low fuel costs, efficiency in converting fuel into energy, low per unit operating and maintenance costs and high levels of power plant availability. For our coal-fired power plants, we leverage theour mine-mouth location advantage to eliminate coal transportation costs that often represent the largest component of
the delivered cost of coal for many other utilities. Additionally, we operate our plants with high levels of availability as compared to industry benchmarks.
We continue to believe that ownership of power generation facilities by our Electric Utilities best serves customers. Rate-based generation assets offer several advantages for customers and shareholders, including:
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.
Proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. Some of our customers, particularly our larger customers, are demanding more renewable and cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from voters, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest, we have filedcreated and received approvals for approval of new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmentgovernmental agency customer requests for renewable energy resources in South Dakota and Wyoming. TheseTo meet the renewable energy commitments under the new tariffs, we also received approval from the Wyoming Public Service Commission to build the Corriedale wind project, a 52.5 MW wind farm to be constructed near Cheyenne, Wyoming. The $79 million project is expected to be in service by year-end 2020. Supporting our renewable energy efforts mayin Colorado, in November 2019, we successfully commissioned Busch Ranch II, a 60 MW wind farm near Pueblo, Colorado, to provide potential investment opportunitiesrenewable energy to incorporate more wind and solar generation into our generation fleet to meet customers’ requests or legislative requirements.Colorado Electric utility.
To date, many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. SomeIn addition, some states have either enacted or are considering legislation setting GHG emissions reduction targets. Federal legislation for both renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely providedrive the need for significant investment opportunities forin our Electric Utilities and Gas Utilities and Power Generation segment.segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility we are responsible for providing safe, reliable and affordable sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with renewable energy standards and GHG emission regulations that balancebalances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.
Build and maintain strong relationships with wholesale power customers of our utilities and our power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be an important provider of electricity to wholesale utility customers, who will continue to need products such as capacity and energy to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns for shareholders over the long-term than we would by selling energy into more volatile energy spot markets. In addition, relationships that we have established with wholesale power customers have developed into other opportunities. MEAN, MDU and the City of Gillette, Wyoming were wholesale power customers that are now joint minority owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues.
Vertically integrate businesses that are supportive of our Electric and Gas utility businesses. While our primary focus is on growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to our utilities. We currently own and operate a coal minepower generation and power generationmining assets that are vertically integrated into and supportive of our Electric Utilities. These operations are located at our utility-generating complexes and are physically integrated into our Electric Utility operations.
Our surface coal mine is located immediately adjacent to our Gillette energy complex in northeastern Wyoming, where allThe Power Generation segment currently owns five of our coal-fired power plants are located. We operate and own majority interests infacilities, four of the five power plants. We own 20% of the fifth power plant which is operated by the majority owner. The coal mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing coal transportation costs. On average, the coal can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel toare contracted with our power plants when compared to other coal-fired and gas-fired power plants. Nearly all of the mine’s coal production is sold to the five on-site, mine-mouth generation facilitiesaffiliate Electric Utilities under long-term supply contracts. Approximately one-half of our coal is sold under cost-plus contracts with affiliates. A small portion of the mine’s coal production is sold to off-site industrial customers and delivered by truck.
power purchase agreements. Our Power Generation segment has an experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed 1920 coal-fired, gas-fired and renewable generation projects since 1995 with aggregate project costs in excess of $2$2.1 billion. This groupteam also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the company’s generation assets. In certain states, our Electric Utilities are required to competitively bid for generation resources needed to serve customers. Generally, our Power Generation segment submits bids in response to those competitive solicitations. Our Power Generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs. The Power Generation segment currently owns three
Our surface coal mine is located immediately adjacent to our Gillette energy complex in northeastern Wyoming, where all five of our coal-fired power plants are located. We operate and own majority interests in four of our five power plants. We own 20% of the fifth power plant which are contracted withis operated by a majority owner. The mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our affiliate Electric Utilitiespower plants when compared to other coal-fired and gas-fired power plants. Nearly all of the mine’s production is sold to the five on-site, mine-mouth generation facilities under long-term power purchase agreements. In addition, Power Generationsupply contracts. Approximately one-half of our production is currently building a 60 MW wind farm for Colorado Electric after winning a solicitation for renewable energy.sold under cost-plus contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck.
Expand utility operations through selective acquisitions of electric and gas utilities. The electric and natural gas utility industries have consolidated significantly over the past two decades and continue to consolidate. We have successfully acquired and integrated numerous utility systems since 2005, including two large, transformational acquisitions - the Aquila utility propertiesTransaction in 2008 and SourceGas Transaction in 2016. Through these acquisitions, we developed a scalable platform that simplifies the rapid integration of acquired utilities, providing significant benefits to both customers and shareholders. The company targets small to large utilities, including municipal and private utility systems, located primarily in geographies that are near to or contiguous with our existing utility service territories and can provide long-term value for both customers and shareholders. In the near-term, we do not expect to pursue large utility acquisitions, particularly given the high valuation multiples realized in recent utility transactions. We will continue to pursue the purchase of small utility systems within or near our geographic footprint, which can be quickly and efficiently integrated into our existing utilities. As pipeline regulations continue to increase, we believe there will be more opportunities to purchase these smaller and more rural utility systems.
Grow our dividend. We are extremely proud of our track record forof annual dividend increases for shareholders. In January 2019, we2020, our Board of Directors declared a quarterly dividend of $0.505$0.535 per share, equivalent to an annual dividend rate of $2.02$2.14 per share. This current annual equivalent rate represents an increase of 5% over the total 2018 dividend of $1.93$2.14 per share, if declared and the 49thpaid in 2020, will represent 50 consecutive years of annual dividend increase.increases. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%. This target payout ratio provides the flexibility for greater increases to our dividend during periods of relatively slow earnings growth.
Maintain an investment grade credit rating and ready access to debt and equity capital markets. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating.
Prospective Information
We expect to generate long-term growth through the expansion of integrated utilities and supporting operations. Sustained growth requires continued capital deployment. Our integrated energy portfolio, focused primarilypredominately on regulated utilities, provides growth opportunities, yet avoids concentrating business risk. We expect much of our growth in the next few years will come from the need for capital deployment opportunities at our utilities and continued focus on improving efficiencies and reducingcontrolling costs. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plan. Prospective information for our operating segments should be read in conjunction with our business strategy discussed above, and our 20182019 company highlights discussed below.
Our discussion and analysis for the year ended December 31, 2019 compared to 2018, as well as discussion and analysis of the results of operations for the year ended December 31, 2018 compared to 2017 given segment reporting changes adopted by the Company in 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2018 compared to 2017, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of OperationsOperations” in our Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 19, 2019.
Executive Summary and Overview
|
| | | | | | | | | | | | | | | |
| | 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 2016include 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. |
The following business group and segmentSegment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.
Results of Operations
Consolidated Summary and Overview
|
| | | | | | | | | | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| (in millions, except per diluted share amounts) | Income | EPS | | Income | EPS | | Income | EPS |
| | | | | | | | | |
| Net income from continuing operations available for common stock | $ | 199.3 |
| $ | 3.28 |
| | $ | 265.3 |
| $ | 4.78 |
| | $ | 194.1 |
| $ | 3.52 |
|
| Net (loss) from discontinued operations | — |
| — |
| | (6.9 | ) | (0.12 | ) | | (17.1 | ) | (0.31 | ) |
| Net income available for common stock | $ | 199.3 |
| $ | 3.28 |
| | $ | 258.4 |
| $ | 4.66 |
| | $ | 177.0 |
| $ | 3.21 |
|
| | | | | | | | | |
2019 Compared to 2018
The variance to the prior year included the following:
Electric Utilities’ adjusted operating income increased $4.4 million due to reduced purchased power capacity costs, increased rider revenues and the prior year Wyoming Electric PCA settlement partially offset by higher operating expenses driven by outside services and employee costs;
Gas Utilities’ adjusted operating income increased $4.7 million primarily due to new customer rates and rider revenues, customer growth and increased transport and transmission driven by increased volumes from new and existing customers partially offset by higher operating expenses driven by outside services and employee costs;
Power Generation’s adjusted operating income increased $2.2 million primarily due to higher revenue from increased wind MWh sold and higher PPA pricing partially offset by higher depreciation and property taxes from new wind assets;
Mining’s adjusted operating income decreased $3.7 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;
Corporate and Other expenses decreased $1.4 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;
A $20 million pre-tax non-cash impairment in 2019 of our investment in equity securities of a privately held oil and gas company;
We expensed $5.4 million of development costs related to projects we no longer intend to construct; and
Increased tax expense of $53 million primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially offset by a prior year $4.0 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes and current year $5.9 million federal PTCs and related state ITCs associated with new wind assets.
2018 Compared to 2017
Income from continuing operations available for common stock was $265 million, or $4.78 per diluted share in 2018 compared to $194 million, or $3.52 per diluted share in 2017. The variance when comparing 2018 to 2017 included the prior year was primarilyfollowing:
Electric Utilities’ adjusted operating income decreased $21.9 million due to:
to TCJA benefits delivered to customers, the Wyoming Electric PCA settlement and higher operating expenses partially offset by increased rider revenues and favorable weather;
Gas Utilities’ earnings, excluding tax reform impacts,adjusted operating income increased approximately $87$0.1 million primarily due to the recognitioncolder winter weather, new customer rates, customer growth and increased transport and transmission offset by TCJA benefits delivered to customers and higher operating expenses;
Power Generation’s adjusted operating income decreased $4.1 million primarily due to a decrease in MWh sold and higher operating expenses;
Mining’s adjusted operating income increased $2.8 million primarily due to increase in price per ton sold and lower operating expenses;
Corporate and Other expenses decreased $3.3 million primarily due to prior year acquisition costs; and
Increased tax benefit of $97 million primarily due to 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 occurringreduction 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 Federalfederal corporate income tax rate as a result offrom 35% to 21% from the TCJA. TCJA, effective January 1, 2018.
The impacts to ourfollowing table summarizes select financial results by operating segmentssegment and Corporate and Other for 2018 and 2017 weredetails significant items (in millions)thousands):
| | | Segment | 2018 | 2017 | |
| | | For the Years Ended December 31, |
| | | 2019 | Variance | 2018 | Variance | 2017 |
| | | (in thousands) |
| Revenue | | |
| Revenue | | $ | 1,885,669 |
| $ | (11,573 | ) | $ | 1,897,242 |
| $ | 83,721 |
| $ | 1,813,521 |
|
| Intercompany eliminations | | (150,769 | ) | (7,795 | ) | (142,974 | ) | (9,719 | ) | (133,255 | ) |
| | | $ | 1,734,900 |
| $ | (19,368 | ) | $ | 1,754,268 |
| $ | 74,002 |
| $ | 1,680,266 |
|
| | | |
Adjusted operating income (a) | | |
Electric Utilities | $ | (4.2 | ) | $ | 23.4 |
| $ | 160,297 |
| $ | 4,428 |
| $ | 155,869 |
| $ | (21,868 | ) | $ | 177,737 |
|
| Gas Utilities | 0.5 |
| (6.8 | ) | 189,971 |
| 4,732 |
| 185,239 |
| 134 |
| 185,105 |
|
| Power Generation | (0.7 | ) | 23.8 |
| 44,779 |
| 2,165 |
| 42,614 |
| (4,076 | ) | 46,690 |
|
| Mining | (0.5 | ) | 2.7 |
| 12,627 |
| (3,713 | ) | 16,340 |
| 2,840 |
| 13,500 |
|
| Corporate and Other | 0.9 |
| (35.5 | ) | (1,632 | ) | 1,393 |
| (3,025 | ) | 3,271 |
| (6,296 | ) |
| Total tax (expense) benefit | $ | (4.0 | ) | $ | 7.6 |
| |
| | | 406,042 |
| 9,005 |
| 397,037 |
| (19,699 | ) | 416,736 |
|
| | | |
| Interest expense, net | | (137,659 | ) | 2,316 |
| (139,975 | ) | (2,873 | ) | (137,102 | ) |
| Impairment of investment | | (19,741 | ) | (19,741 | ) | — |
| — |
| — |
|
| Other income (expense), net | | (5,740 | ) | (4,560 | ) | (1,180 | ) | (3,288 | ) | 2,108 |
|
| Income tax benefit (expense) | | (29,580 | ) | (53,247 | ) | 23,667 |
| 97,034 |
| (73,367 | ) |
| Income from continuing operations | | 213,322 |
| (66,227 | ) | 279,549 |
| 71,174 |
| 208,375 |
|
| (Loss) from discontinued operations, net of tax | | — |
| 6,887 |
| (6,887 | ) | 10,212 |
| (17,099 | ) |
| Net income | | 213,322 |
| (59,340 | ) | 272,662 |
| 81,386 |
| 191,276 |
|
| Net income attributable to noncontrolling interest | | (14,012 | ) | 208 |
| (14,220 | ) | 22 |
| (14,242 | ) |
| Net income available for common stock | | $ | 199,310 |
| $ | (59,132 | ) | $ | 258,442 |
| $ | 81,408 |
| $ | 177,034 |
|
| | | |
_____________
| |
| (a) | In 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information. |
Net income (loss) available for common stock was $258 million, or $4.66 per diluted share in 2018, compared to $177 million, or $3.21 per share in 2017. (Loss) from discontinued operations was $(6.9) million or $(0.12) per diluted share in 2018 compared to $(17) million or $(0.31) per diluted share in 2017. Discontinued operations in 2017 included an after-tax fair value impairment of assets of approximately $13 million.
20182019 Overview of Business Segments and Corporate Activity
Electric Utilities
On December 17, 2018,13, 2019, Colorado Electric issued a request for proposals for its Renewable Advantage program, to potentially add up to 200 MW of renewable energy to its southern Colorado system. A competitive solicitation process for the addition of cost-effective, utility-scale renewable energy projects includes wind, solar and battery storage to supplement existing natural gas and wind generation power supplies Bidders have until February 15, 2020, to submit proposals, which will be reviewed by an independent evaluator overseen by the CPUC. Based on the outcome of the bidding process, projects would be placed in service no later than 2023.
In July 2019, South Dakota Electric and Wyoming Electric filedreceived approvals for approval with the SDPUCRenewable Ready program 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 arelated jointly-filed CPCN to construct a $57 million, 40 MWCorriedale. The 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 governedwill be jointly owned by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSCtwo electric utilities to deliver renewable energy for large commercial, industrial and approval by FERC. The review process is expected to be completed by year-end 2019.
On October 31, 2018, Wyominggovernmental agency customers. In November 2019, South Dakota Electric received approval from the SDPUC to increase the offering under the program by 12.5 MW. The two electric utilities also received a determination from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlierto increase the project to 52.5 MW. The $79 million project is expected to be 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 escalateservice by 3% annually through 2022.year-end 2020.
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.
Heating degree days for the year ended December 31, 2018 were 3% higher than normal compared to 11% lower 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,September 17, 2019, South Dakota Electric placed in service a 33-milecompleted construction on the final 94-mile segment of a $70 million, 175-mile 230-kVelectric 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-mile2018, and the second 33-mile segment is expected to bewas placed in service by the end of 2019.on November 20, 2018.
Colorado Electric set a new all-time and summer peak load:
On April 25, 2018,July 19, 2019, Colorado Electric received approval fromset a new all-time and summer peak load of 422 MW, exceeding the CPUC to contract with Black Hillsprevious peak of 413 MW set in June 2018.
Wyoming Electric Generationset a new all-time and summer peak load, and also set a new winter peak load:
On July 19, 2019, Wyoming Electric set a new all-time and summer peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.
On December 16, 2019, Wyoming Electric set a new winter peak load of 247 MW, exceeding the previous peak of 238 MW set in December 2018.
Cooling degree days for the 60 MW Busch Ranch II wind project. The project is currently under construction and is expectedyear ended December 31, 2019 were 14% higher than the normal compared to be29% higher than normal in service by2018.
Heating degree days for the end of 2019. This renewable energy will enable Colorado Electricyear ended December 31, 2019 were 5% higher than normal compared to comply with Colorado's Renewable Energy Standard.3% higher than normal in 2018.
Gas Utilities
Gas Utilities continued to consolidate utility jurisdictions within the States of Colorado, Nebraska, and Wyoming:
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| ◦ | On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. A new, single statewide rate structure will be effective March 1, 2020. New rates are expected to generate $13 million in new revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability. |
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| ◦ | On February 1, 2019, Colorado Gas submitted a rate review with the CPUC to consolidate rates, tariffs and services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and recommending a rate decrease. Colorado Gas has filed exceptions to the ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 and completed in early 2019. |
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| ◦ | On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two natural gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services. |
Rate Review updates:
On FebruaryDecember 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 withplaced in service 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 gasNatural Bridge pipeline project to enhance supply reliability and delivery capacity for approximately 57,000 customers in central Wyoming. The new 12-inch steel pipeline known asinterconnects from a supply point near Douglas, Wyoming, to facilities near Casper, Wyoming. The associated investment was included in the Natural Bridge Pipeline, is planned to beWyoming Gas rate review completed in service in lateDecember 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, 20182019 were 5% higher than normal compared to 2% higher than the 30-year average (normal) compared to 10% lower than normal in 2017.2018.
Power Generation
On December 11, 2018,November 26, 2019, Black Hills Electric Generation purchased a 50% ownership interestplaced in the 29 MWservice Busch Ranch I Wind Farm, previously owned by AltaGas, for $16 million.
On April 25, 2018,II. Through a competitive bidding process, Black Hills Electric Generation was selected to providedeliver renewable energy under a 25-year PPA to Colorado Electric.
On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of renewable energy to ColoradoWyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On December 23, 2019, the Busch Ranch II wind project, which is expectedCompany filed a response to bequestions from the FERC and awaits a decision from FERC.
Mining
In October 2019, negotiations were completed for the price reopener in service by the endcontract with the Wyodak power plant. Effective July 1, 2019, the new price was reset at $17.94 per ton with customary escalators, compared to the prior contract price of 2019.$18.25 per ton. The contract expires on December 31, 2022 and negotiations are underway to extend the contract.
Corporate and Other
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, 2018,3, 2019, we completed a public debt offering of $400$700 million principal amount of 4.350%in senior unsecured notes. The proceedsProceeds were used to repay the $299$400 million principal amountCorporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.
During the year ended December 31, 2019, we issued a total of 1.3 million shares of common stock for net proceeds of $99 million under our RSNsATM equity offering program.
On June 17, 2019, we amended our Corporate term loan due 2028July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to 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.
Discontinued Operations
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.
2017 Compared to 2016
Income from continuing operations available for common stock was $194 million, or $3.52 per diluted share in 2017 compared to $137 million, or $2.57 per diluted share in 2016. The variance to the prior year was primarily due to:
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:
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◦ | Electric Utilities - $23 million tax benefit |
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◦ | Gas Utilities - $6.8 million tax expense |
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◦ | Power Generation - $24 million tax benefit |
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◦ | Mining - $2.7 million tax benefit |
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◦ | 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.
Net income (loss) available for common stock was $177 million, or $3.21 per diluted share in 2017, compared to $73 million, or $1.37 per share in 2016. (Loss) from discontinued operations was $(17) million or $(0.31) per diluted share in 2017 compared to $(64) million or $(1.20) per diluted share in 2016. Discontinued operations in 2017 included an after-tax fair value impairment of assets of approximately $13 million compared to 2016 which included non-cash after-tax oil and gas property impairment charges of $67 million. Also included in 2016 discontinued operations was a $5.8 million tax benefit recognized from additional percentage depletion deductions that were claimed with respect to our oil and gas properties involving prior years.
2017 Overview of Business Segments and Corporate Activity
Electric Utilities
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 Proceeds from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 MW of renewable energyOctober 3, 2019 debt transaction were used 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 ofrepay this proposal.term loan.
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.
Gas Utilities
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.
The Gas Utilities also experienced cooler summer temperatures and higher precipitation levels during the third quarter of 2017 compared to the same period in 2016, which reduced the irrigation load delivered to agricultural customers, primarily in our Nebraska service territory.
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.
Corporate and Other
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.
Discontinued Operations
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.
Operating ResultsGas Utilities
A discussion of operating results from our business segments follows.
All amounts are presented on a pre-tax basis unless otherwise indicated.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.
In our Management Discussion and Analysis of Results of Operations, gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenues less costcontinued to consolidate utility jurisdictions within the States of gas sold. Our gross margin is impacted by the fluctuations in power purchasesColorado, Nebraska, and natural gas and other fuel supplyWyoming:
costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.
Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Electric Utilities
Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| | 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 endedOn December 31, 2018 to reflect the lower federal income tax rate11, 2019, Wyoming Gas received approval from the TCJAWPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. A new, single statewide rate structure will be effective March 1, 2020. New rates are expected to generate $13 million in new revenue based on our existing rate tariffs. This reductiona return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to revenues is offset by lower tax expenserecover integrity investments for system safety and has no impact on overall results. |
| |
(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.reliability. |
|
| | | |
| | 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,On February 1, 2019, Colorado Gas submitted a rate review with the CPUC to consolidate rates, tariffs and Wygen II. |
| |
(b) | 2016 reflectsservices of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a planned outage at Wygen III, an extended planned outage at Wyodaknew rider mechanism to recover future safety and an unplanned outage at Neil Simpson II. |
| |
(c) | 2017integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and 2016 were lower duerecommending a rate decrease. Colorado Gas has filed exceptions to the additionALJ’s recommended decision. A decision by the CPUC is expected by the end of Peak View Wind Project with ownership transferMarch 2020. Legal consolidation was previously approved by the CPUC in November, 2016.late 2018 and completed in early 2019. |
2018 Compared to 2017
Gross margin(a) decreased over the prior year as a result of:
|
| | | |
| | (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 | ) |
____________________
| |
(b) | Horizon Point shared facility revenueOn October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two natural gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is offsetexpected to be filed by facility expenses at our operating segmentsmid-year 2020 to consolidate the rates, tariffs and has no impact on consolidated results.services. |
OperationsOn December 1, 2019, Wyoming Gas placed in service the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and maintenance increased primarily duedelivery capacity for customers in central Wyoming. The new 12-inch steel pipeline interconnects from a supply point near Douglas, Wyoming, to facilities near Casper, Wyoming. The associated investment was included in the Wyoming Gas rate review completed in December 2019.
Heating degree days at the Gas Utilities for the year ended December 31, 2019 were 5% higher facility coststhan normal compared to 2% higher than normal in 2018.
Power Generation
On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II. Through a competitive bidding process, Black Hills Electric Generation was selected to deliver renewable energy under a 25-year PPA to Colorado Electric.
On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of $4.5 million and higher employee costsa new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of $3.6 million driven primarily by labor and benefits. Vegetation management expenses increased over the prior year by $2.9 million, contractor and consulting expenses increased by $1.2 million and property taxes increased by $1.0 million due to a higher asset base.
Depreciation and amortization increased primarily due to higher asset base driven by the prior year additions of Horizon Point and the Teckla-Lange transmission line as well as the current year completionagreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On December 23, 2019, the first segment ofCompany filed a response to questions from the Rapid City-Stegall transmission line.FERC and awaits a decision from FERC.
Interest expense, net was comparable toMining
In October 2019, negotiations were completed for the same periodprice reopener in the prior year.
Other (expense) income, net decreased due tocontract with the presentation change of non-service pension costs to Other income (expense) inWyodak power plant. Effective July 1, 2019, the current year, previously reported in Operations and maintenance, and higher prior year AFUDC associatednew price was reset at $17.94 per ton with higher prior year capital spend.
Income tax benefit (expense): The effective tax rate increased in 2018 due to a prior year $23 million benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. In addition, current year expense increased due to $4.2 million of tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. This was partially offset by the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.
2017 Compared to 2016
Gross margin(a) increased over the prior year as a result of:
|
| | | |
| | (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 |
|
____________________
| |
(b) | Includes approximately 1.5 months of Horizon Point shared facility revenue. |
Operations and maintenance increased primarily due to $4.8 million of higher employee costs as a result of prior year integration activities and transition expenses charged to Corporate and Other, $2.6 million of higher generation outage expenses, $1.9 million of higher property taxes with an increased asset base, and $1.7 million of higher operating expenses from the Peak View Wind Project and the 40 MW gas turbine at the Pueblo Airport Generating Station. An additional $1.3 million of indirect corporate costs are included at the Electric Utilities; these costs were previously charged to our Oil and Gas segment, now reported as discontinued operations.
Depreciation and amortization increased primarily due to a higher asset base driven partially by the addition of the Peak View Wind Project and the 40 MW gas turbine at the Pueblo Airport Generating Station.
Interest expense, net increased primarily due to higher intercompany debt resulting from additional investments ascustomary escalators, compared to the prior year.
Other (expense) income, net decreased due to reduced AFUDC with lower capital spend.
Income tax benefit (expense):contract price of $18.25 per ton. The effective tax rate was lower in 2017 primarily due to a $23 million benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJAcontract expires on December 22, 2017.31, 2022 and negotiations are underway to extend the contract.
Corporate and Other
On October 3, 2019, we completed a public debt offering of $700 million in senior unsecured notes. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.
During the year ended December 31, 2019, we issued a total of 1.3 million shares of common stock for net proceeds of $99 million under our ATM equity offering program.
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This benefit was primarily relatedamendment increased total commitments to $400 million from $300 million and extended the revaluation ofterm through June 17, 2021 on substantially similar terms and covenants. The net operating losses and other tax basis items not included inproceeds were used to pay down short-term debt. Proceeds from the ratemaking construct. Production tax credits associated with the Peak View Wind Project increased by $4.0 million reflecting a full year of production tax credits comparedOctober 3, 2019 debt transaction were used to two months in 2016. The prior year included a $1.3 million benefit related to the flow-through treatment of a treasury grant related to the Busch Ranch I Wind Project.repay this term loan.
Gas Utilities
Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):continued to consolidate utility jurisdictions within the States of Colorado, Nebraska, and Wyoming:
|
| | | | | | | | | | | | | | | |
| | 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 endedOn December 31, 2018 to reflect the lower federal income tax rate11, 2019, Wyoming Gas received approval from the TCJAWPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. A new, single statewide rate structure will be effective March 1, 2020. New rates are expected to generate $13 million in new revenue based on our existing rate tariffs. This reductiona return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to revenues is offset by lower tax expenserecover integrity investments for system safety and has no impact on overall results. |
| |
(b) | Non-GAAP measure.reliability. |
2018 Compared to 2017
Gross margin(a) increased over the prior year as a result of:
|
| | | |
| | (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 |
|
___________________
| |
(b) | Heating degree days atOn February 1, 2019, Colorado Gas submitted a rate review with the CPUC to consolidate rates, tariffs and services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas Utilities foralso requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the year ended December 31,ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and recommending a rate decrease. Colorado Gas has filed exceptions to the ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 were 2% higher than the 30-year average (normal) compared to 10% lower than normaland completed in 2017.early 2019. |
Operations and maintenance increased primarily due to higher employee costs of $11.8 million driven by labor, benefits and additional headcount. Outside services, consulting, and contractor expenses increased by $4.0 million due primarily to expenses related to jurisdictional simplification. In addition, facility costs increased by $4.7 million and bad debt expense increased by $2.1 million driven by the current year increase in revenues.
Depreciation and amortization increased primarily due to higher asset base driven by previous and current year capital expenditures.
Interest expense, net increased due to higher corporate allocations from financing activities.
Other (expense) income, net was comparable to the same period in the prior year.
Income tax: The effective tax rate decrease was due to legal restructuring to enable jurisdictional simplification that resulted in the recognition of a deferred tax benefit of approximately $73 million associated with amortizable goodwill for tax purposes. The current year rate also reflects the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018. In the prior year there was additional tax expense of $6.8 million as a result of the TCJA enacted on December 22, 2017, partially offset by $4.1 million tax benefit recognized in the prior year from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition.
2017 Compared to 2016
Gross margin(a) increased over the prior year as a result of:
|
| | | |
| | (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 measureOn October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two natural gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services. |
OperationsOn December 1, 2019, Wyoming Gas placed in service the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and maintenance increased primarily duedelivery capacity for customers in central Wyoming. The new 12-inch steel pipeline interconnects from a supply point near Douglas, Wyoming, to additional operating costs of approximately $19 million forfacilities near Casper, Wyoming. The associated investment was included in the acquired SourceGas utilities, reflecting a full twelve months of resultsWyoming Gas rate review completed in 2017 as compared to approximately 10.5 months in 2016. Employee-related expenses increased $6.2 million for the Black Hills legacy Gas Utilities as a result of prior year integration activities and transition expenses charged to Corporate and Other. An additional $1.6 million of indirect corporate costs are includedDecember 2019.
Heating degree days at the Gas Utilities; these costsUtilities for the year ended December 31, 2019 were previously charged5% higher than normal compared to our Oil and Gas segment, now reported as discontinued operations. A variety of smaller items contribute to the partially offsetting decrease2% higher than normal in operations and maintenance expenses.2018.
Depreciation and amortization increased primarily due to additional depreciation from the acquired SourceGas utilities.
Interest expense, net increased primarily due to additional interest expense from the acquired SourceGas utilities.
Income tax: The effective tax rate increased in 2017 primarily due to additional tax expense of $6.8 million as a result of the TCJA enacted on December 22, 2017 and from a $2.2 million tax benefit recognized in the prior year primarily related to favorable flow-through adjustments recognized in accordance with prescribed regulatory treatment. Partially offsetting these is a $4.1 million tax benefit recognized in the current year from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition.
Power Generation
Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| | 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 |
|
On April 14, 2016,November 26, 2019, Black Hills Electric Generation soldplaced in service Busch Ranch II. Through a 49.9%, noncontrolling interest in Black Hills Colorado IPP.competitive bidding process, Black Hills Electric Generation continueswas selected to bedeliver renewable energy under a 25-year PPA to Colorado Electric.
On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the majority owner and operatorcapacity need for Wyoming Electric at the expiration of the facility, which is contracted to provide capacity and energy through 2031 tocurrent agreement on December 31, 2022. If approved, Black Hills Colorado Electric. The net income allocableWyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On December 23, 2019, the noncontrolling interest holders is based on ownership interestsCompany filed a response to questions from the FERC and awaits a decision from FERC.
Mining
In October 2019, negotiations were completed for the price reopener in the contract with the exception of certain agreed upon adjustments.
|
| | | |
| | 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 Compared to 2017
Net income available for common stock forWyodak power plant. Effective July 1, 2019, the Power Generation segmentnew price was $21 million for the year ended December 31, 2018,reset at $17.94 per ton with customary escalators, compared to Net income available for common stock of $46 million for the same period in 2017. Revenue decreased in the current year due to a decrease in MWh sold, primarily from a planned outage at Wygen I. Operating expenses increased due to higher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation. Interest expense increased from the same period in the prior year due to higher interest rates. The variance in tax expense is primarily due to a prior year $24 million tax benefit recognized from the revaluation of deferred tax liabilities in accordance with the TCJA enacted on December 22, 2017 partially offset by the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.
2017 Compared to 2016
Net income available for common stock for the Power Generation segment was $46 million for the year ended December 31, 2017, compared to Net income available for common stock of $26 million for the same period in 2016. Revenue and operating expenses were comparable to the same period in the prior year and depreciation expense increased on non-leased assets. The variance to the prior year was primarily driven by a $24 million tax benefit recognized from the revaluationcontract price of deferred tax liabilities in accordance with the TCJA enacted$18.25 per ton. The contract expires on December 22, 2017.31, 2022 and negotiations are underway to extend the contract.
Mining
Mining operating results for the years ended December 31 were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| | 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 |
|
The following table provides certain operating statistics for the Mining segment (in thousands):
|
| | | | | | |
| | 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. |
2018 Compared to 2017
Net income available for common stock for the Mining segment was $13 million for the year ended December 31, 2018, compared to Net income available for common stock of $14 million for the same period in 2017. Revenue increased primarily due to a 1% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income, net. During the current period, approximately 50% of the mine’s production was sold under contracts that include price adjustments based on actual mining costs, including income taxes.
Operating expenses decreased primarily due to lower major maintenance expenses and lower overburden removal. Other income, net decreased from the prior year due to the presentation change of lease and rental revenue to Revenue in the current year, previously reported in Other income, net. The variance in tax expense is primarily due to a prior year $2.7 million benefit resulting from revaluation of net deferred tax liabilities in accordance with the enactment of the TCJA on December 22, 2017, partially offset by the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective Jan. 1, 2018.
2017 Compared to 2016
Net income available for common stock for the Mining segment was $14 million for the year ended December 31, 2017, compared to Net income available for common stock of $10 million for the same period in 2016. The variance to the prior year was driven by an increase in revenue and lower tax expense, partially offset by higher operating expenses. Revenue increased due to a 10% increase in tons sold driven primarily by an 11-week outage at the Wyodak plant in 2016.
Operations and maintenance expenses increased due to higher equipment major maintenance, higher overburden moved and higher royalties and production taxes on increased revenues, partially offset by lower depreciation, depletion and amortization expense primarily due to lower plant in service and lower asset retirement obligation costs. The effective tax rate is lower in 2017 primarily due to a $2.7 million benefit resulting from revaluation of net deferred tax liabilities in accordance with the enactment of the TCJA on December 22, 2017.
Corporate and Other
On October 3, 2019, we completed a public debt offering of $700 million in senior unsecured notes. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.
During the year ended December 31, 2019, we issued a total of 1.3 million shares of common stock for net proceeds of $99 million under our ATM equity offering program.
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.
Operating Results
A discussion of operating results from our business segments follows.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.
CorporateGross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and Other represents certain unallocated expensespurchased power. Gross margin for corporateour Gas Utilities is calculated as operating revenues less cost of gas sold. Our gross margin is impacted by the fluctuations in power and natural gas purchases and other administrative activities, interest and taxes that supportfuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our reportablecustomers.
Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating segments. Below is a summaryincome as determined in accordance with GAAP as an indicator of operating expenses and tax (expenses) benefits included in Corporate and Otherperformance.
Electric Utilities
Operating results for the years ended December 31:31 for the Electric Utilities were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| (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 | ) |
|
| | | | | | | | | | | | | | | |
| | 2019 | Variance | 2018 | Variance | 2017 |
| | | | | | |
| Revenue | $ | 712,752 |
| $ | 1,301 |
| $ | 711,451 |
| $ | 6,801 |
| $ | 704,650 |
|
| | | | | | |
| Total fuel and purchased power | 268,297 |
| (15,543 | ) | 283,840 |
| 9,477 |
| 274,363 |
|
| | | | | | |
| Gross margin (non-GAAP) | 444,455 |
| 16,844 |
| 427,611 |
| (2,676 | ) | 430,287 |
|
| | | | | | |
| Operations and maintenance | 195,581 |
| 9,406 |
| 186,175 |
| 13,868 |
| 172,307 |
|
| Depreciation and amortization | 88,577 |
| 3,010 |
| 85,567 |
| 5,324 |
| 80,243 |
|
| Total operating expenses | 284,158 |
| 12,416 |
| 271,742 |
| 19,192 |
| 252,550 |
|
| | | | | | |
Adjusted operating income (a) | $ | 160,297 |
| $ | 4,428 |
| $ | 155,869 |
| $ | (21,868 | ) | $ | 177,737 |
|
________________________________
| |
| (a) | Includes certain generalDue to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Electric Utilities Adjusted operating income was revised for the years ended December 31, 2018 and administrativeDecember 31, 2017 which resulted in an increase of $6.4 million and interest expenses that are not reported as discontinued operations.$7.1 million, respectively. |
2019 Compared to 2018
Gross margin increased over the prior year as a result of:
|
| | | |
| | (in millions) |
| Reduction in purchased power capacity costs | $ | 6.5 |
|
| Prior year Wyoming Electric PCA Stipulation settlement | 3.7 |
|
| Rider recovery | 3.1 |
|
| Increased commercial and industrial demand | 1.9 |
|
| Weather | 0.2 |
|
| Other | 1.4 |
|
| Total increase in Gross margin (non-GAAP) | $ | 16.8 |
|
Operations and maintenance expense increased primarily due to $4.7 million of higher employee costs and $2.9 million of higher outside services expenses. Various other expenses comprise the remainder of the increase compared to the prior year.
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
2018 Compared to 2017
Gross margin decreased over the prior year as a result of:
|
| | | |
| | (in millions) |
| TCJA revenue reserve | $ | (22.3 | ) |
| Wyoming Electric PCA Stipulation settlement | (2.6 | ) |
| Other | (1.4 | ) |
Horizon Point shared facility revenue (a) | 9.8 |
|
| Rider recovery | 5.1 |
|
| Weather | 3.6 |
|
| Power Marketing, transmission and Tech Services | 3.5 |
|
| Residential customer growth | 1.6 |
|
| Total increase (decrease) in Gross margin (non-GAAP) | $ | (2.7 | ) |
____________________
| |
| (a) | Horizon Point shared facility revenue was offset by facility expenses at our operating segments and had no impact on consolidated results. |
Operations and maintenance expense increased primarily due to $4.5 million of higher facility costs, $4.1 million of higher outside services expenses, $3.6 million of higher employee costs, and $1.0 million of higher property taxes due to a higher asset base.
Depreciation and amortization increased primarily due to higher asset base driven by current and prior year capital expenditures.
|
| | | |
| | For the year ended December 31, |
Contracted power plant fleet availability (a) | 2019 | 2018 | 2017 |
| | | | |
Coal-fired plants (b) | 92.1% | 93.9% | 88.9% |
Natural gas fired plants and Other plants (c) | 87.9% | 96.4% | 96.1% |
| Wind | 95.6% | 96.9% | 93.3% |
| Total availability | 89.9% | 95.6% | 93.6% |
| | | | |
| Wind capacity factor | 38.7% | 39.2% | 36.7% |
____________________
| |
| (a) | Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet. |
| |
| (b) | 2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III. |
| |
| (c) | 2019 included planned outages at Neil Simpson CT and Lange CT. |
Net loss available for common stock was $(7.6) millionGas Utilities
Operating results for the yearyears ended December 31 2018, compared to Net loss available for common stock of $(43) million for the same period in 2017. The variance fromGas Utilities were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| | 2019 | Variance | 2018 | Variance | 2017 |
| Revenue: | | | | | |
| Natural gas - regulated | $ | 932,111 |
| $ | (10,813 | ) | $ | 942,924 |
| $ | 77,093 |
| $ | 865,831 |
|
| Other - non-regulated services | 77,919 |
| (4,464 | ) | 82,383 |
| 584 |
| 81,799 |
|
| Total revenue | 1,010,030 |
| (15,277 | ) | 1,025,307 |
| 77,677 |
| 947,630 |
|
| | | | | | |
| Cost of natural gas sold: | | | | | |
| Natural gas - regulated | 406,643 |
| (35,887 | ) | 442,530 |
| 61,271 |
| 381,259 |
|
| Other - non-regulated services | 19,255 |
| (368 | ) | 19,623 |
| (8,721 | ) | 28,344 |
|
| Total cost of sales | 425,898 |
| (36,255 | ) | 462,153 |
| 52,550 |
| 409,603 |
|
| | | | | | |
| Gross margin (non-GAAP) | 584,132 |
| 20,978 |
| 563,154 |
| 25,127 |
| 538,027 |
|
| | | | | | |
| Operations and maintenance | 301,844 |
| 10,363 |
| 291,481 |
| 22,291 |
| 269,190 |
|
| Depreciation and amortization | 92,317 |
| 5,883 |
| 86,434 |
| 2,702 |
| 83,732 |
|
| Total operating expenses | 394,161 |
| 16,246 |
| 377,915 |
| 24,993 |
| 352,922 |
|
| | | | | | |
| Adjusted operating income | $ | 189,971 |
| $ | 4,732 |
| $ | 185,239 |
| $ | 134 |
| $ | 185,105 |
|
2019 Compared to 2018
Gross margin increased over the prior year wasas a result of:
|
| | | |
| | (in millions) |
| New rates | $ | 16.2 |
|
| Customer growth - distribution | 5.2 |
|
| Increased transport and transmission | 2.6 |
|
| Weather | (2.2 | ) |
| Decreased mark-to-market on non-utility natural gas commodity contracts | (3.3 | ) |
| Other | 2.5 |
|
| Total increase in Gross margin (non-GAAP) | $ | 21.0 |
|
Operations and maintenance expense increased primarily due to $5.5 million of higher outside services expenses, $1.2 million higher employee costs and $2.0 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures. Various other expenses comprise the remainder of the increase compared to the prior year.
Depreciation and amortization increased primarily due to a higher asset base driven by a decrease in income tax expense, as well as lower operatingprior and interest expenses. The variance fromcurrent year capital expenditures.
2018 Compared to 2017
Gross margin increased over the prior year was due to:
Prior year tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances as a result of:
|
| | | |
| | (in millions) |
Weather (a) | $ | 13.8 |
|
| New rates | 10.7 |
|
| Customer growth - distribution | 5.2 |
|
| Increased mark-to-market on non-utility natural gas commodity contracts | 4.0 |
|
| Increased 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 (non-GAAP) | $ | 25.1 |
|
| |
| (a) | Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than normal compared to 10% lower than normal in 2017. |
Operations and maintenance expense increased primarily due to $11.8 million of the TCJA;higher employee costs, $4.7 million of higher facility costs, $4.0 million of higher outside services expenses and $2.1 million of higher bad debt expense driven by an increase in revenues.
Higher
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year state income tax expense of $4.6 million;capital expenditures.
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.
Power Generation
2017 Compared to 2016
Net (loss) available for common stock was $(43) million for the year ended December 31, 2017, compared to net (loss) available for common stock of $(44) million for the same period in 2016. The variance from the prior year was due to:
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 GasOur Power Generation 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.
Discontinued Operations
Oil and Gas operating results included in discontinued operations for the years ended December 31 were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| | 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 | ) |
|
| | | | | | | | | | | | | | | |
| | 2019 | Variance | 2018 | Variance | 2017 |
| | | | | | |
| Revenue | $ | 101,258 |
| $ | 8,807 |
| $ | 92,451 |
| $ | (2,169 | ) | $ | 94,620 |
|
| | | | | | |
| Total fuel | 9,059 |
| 467 |
| 8,592 |
| (748 | ) | 9,340 |
|
| Operations and maintenance | 28,429 |
| 3,294 |
| 25,135 |
| 2,093 |
| 23,042 |
|
| Depreciation and amortization | 18,991 |
| 2,881 |
| 16,110 |
| 562 |
| 15,548 |
|
| Total operating expenses | 56,479 |
| 6,642 |
| 49,837 |
| 1,907 |
| 47,930 |
|
| | | | | | |
Adjusted operating income (a) | $ | 44,779 |
| $ | 2,165 |
| $ | 42,614 |
| $ | (4,076 | ) | $ | 46,690 |
|
____________________
| |
| (a) | Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Power Generation Adjusted operating income was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(5.7) million and $(6.5) million, respectively. |
2019 Compared to 2018
Revenue increased in the current year due to increased wind MWh sold and higher PPA prices. Operating expenses increased in the current year primarily due to higher depreciation and property taxes from new wind assets.
2018 Compared to 2017
Net lossRevenue decreased in 2018 due to a decrease in MWh sold, primarily from discontinued operations was $(6.9) million for 2018, compareda planned outage at Wygen I. Operating expenses increased due to Net loss from discontinued operations of $(17) millionhigher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation.
|
| | | |
| | For the year ended December 31, |
Contracted power plant fleet availability (a) | 2019 | 2018 | 2017 |
| | | | |
Coal-fired plant (b) | 94.5% | 85.8% | 96.9% |
| Natural gas-fired plants | 98.6% | 99.4% | 99.2% |
Wind (c) | 90.6% | N/A | N/A |
| Total availability | 95.0% | 95.9% | 98.6% |
| | | | |
Wind capacity factor (c) | 23.5% | N/A | N/A |
___________
| |
| (a) | Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet. |
| |
| (b) | Wygen I experienced a planned outage in 2018 |
| |
| (c) | Change from 2018 to 2019 is driven by Black Hills Electric Generation’s acquisition of new wind assets. |
Mining
Mining operating results for the same period in 2017. years ended December 31 were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| | 2019 | Variance | 2018 | Variance | 2017 |
| | | | | | |
| Revenue | $ | 61,629 |
| $ | (6,404 | ) | $ | 68,033 |
| $ | 1,412 |
| $ | 66,621 |
|
| | | | | | |
| Operations and maintenance | 40,032 |
| (3,696 | ) | 43,728 |
| (1,154 | ) | 44,882 |
|
| Depreciation, depletion and amortization | 8,970 |
| 1,005 |
| 7,965 |
| (274 | ) | 8,239 |
|
| Total operating expenses | 49,002 |
| (2,691 | ) | 51,693 |
| (1,428 | ) | 53,121 |
|
| | | | | | |
| Adjusted operating income | $ | 12,627 |
| $ | (3,713 | ) | $ | 16,340 |
| $ | 2,840 |
| $ | 13,500 |
|
The variance is driven by lower revenues duefollowing table provides certain operating statistics for the Mining segment (in thousands):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Tons of coal sold | 3,716 |
| 4,085 |
| 4,183 |
|
| Cubic yards of overburden moved | 8,534 |
| 8,970 |
| 9,018 |
|
| Coal reserves at year-end (in tons) | 185,448 |
| 189,164 |
| 194,909 |
|
| | | | |
| Revenue per ton | $ | 15.94 |
| $ | 16.11 |
| $ | 15.93 |
|
2019 Compared to property sales and higher losses on sales of operating assets, partially offset by lower oil and gas operating expenses and lower employee costs. 2018
Current year depreciation expense is representative of the amortization of the remaining book value of accounting software. Depreciation and depletion expense was recorded under full cost accounting, which ceased November 1, 2017 due to reclassification to assets held for sale. There were no impairments during 2018 compared to a $20 million non-cash fair value impairment of assets held for sale in 2017.
2017 Compared to 2016
Net loss from discontinued operations was $(17) million for 2017, compared to Net loss from discontinued operations of $(64) million for the same period in 2016. The variance is driven byrevenue decreased revenues primarily due to lower commodity prices9% fewer tons sold driven primarily by planned and decreased production offset by lower operatingunplanned generation facility outages at the Wyodak Plant. Operating expenses due to lower employee costs as a result of reduced staffing. Depreciation and depletion decreased due to the reduction of our full cost pool resulting from 2016 ceiling test impairments and no depletion recorded on assets held for sale beginning on November 1, 2017.
In 2017, we recorded a $20 million non-cash fair value impairment of assets held for sale compared to 2016 impairments that included a $14 million write-down of depreciable properties excluded from our full-cost pool and a ceiling test write-down of $93 million, offset by lower income tax benefit in 2017 compared to 2016. Interest expense decreased primarily due to lower capitalizedroyalties and production taxes on decreased revenues and lower fuel, labor, and major maintenance expenses.
2018 Compared to 2017
Revenue increased primarily due to a 1% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income, net. Operating expenses decreased primarily due to lower major maintenance expenses.
Corporate and Other
Corporate and Other operating results for the years ended December 31 were as follows (in thousands):
|
| | | | | | | | | | | | | | | |
| (in thousands) | 2019 | Variance | 2018 | Variance | 2017 |
| | | | | | |
Adjusted operating (loss) (a) | $ | (1,632 | ) | $ | 1,393 |
| $ | (3,025 | ) | $ | 3,271 |
| $ | (6,296 | ) |
____________
| |
| (a) | Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Corporate and Other Adjusted operating (loss) was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(0.7) million and $(0.6) million, respectively. |
2019 Compared to 2018
The variance in Adjusted operating (loss) was primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.
2018 Compared to 2017
The variance in Adjusted operating (loss) was primarily due to prior year acquisition costs.
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)
|
| | | | | | | | | | | | | | | |
| (in thousands) | 2019 | Variance | 2018 | Variance | 2017 |
| | | | | | |
| Interest expense, net | $ | (137,659 | ) | $ | 2,316 |
| $ | (139,975 | ) | $ | (2,873 | ) | $ | (137,102 | ) |
| Impairment of investment | (19,741 | ) | (19,741 | ) | — |
| — |
| — |
|
| Other income (expense), net | (5,740 | ) | (4,560 | ) | (1,180 | ) | (3,288 | ) | 2,108 |
|
| Income tax benefit (expense) | (29,580 | ) | (53,247 | ) | 23,667 |
| 97,034 |
| (73,367 | ) |
2019 Compared to 2018
Impairment of Investment
For the year ended December 31, 2019, we recorded a pre-tax non-cash write-down of $20 million in our investment in equity
securities of a privately held oil and gas company. The impairment was triggered by a deterioration in earnings performance of
the privately held oil and gas company and an adverse change in future natural gas prices. See Note 1 of the Notes to Consolidated Financial Statements for additional details.
Other Income (Expense)
For the year ended December 31, 2019, we expensed $5.4 million of development costs related to projects we no longer intend to construct.
Income Tax Benefit (Expense)
The increase in tax expense was primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially offset by:
A prior year $(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes;
Current year $3.8 million of federal PTCs and $2.1 million of related state ITCs associated with new wind assets;
A current year $1.9 million tax benefit from increased repair activity in flow-through regulatory jurisdictions;
A current year $1.4 million tax benefit for incremental excess deferred tax amortization related to tax reform; and
A current year $3.4 million tax benefit from a federal tax loss carry-back claim including interest. We identified certain qualified expenses that extend beyond the typical two-year carry-back period.
2018 Compared to 2017
Other Income (Expense)
The variance in Other income (expense), net was primarily due to the presentation change of non-service pension costs to Other income (expense) in 2018, previously reported in Operations and maintenance.
Income Tax Benefit (Expense)
The variance in Income tax benefit (expense) was primarily due to a $73 million tax benefit in 2018 resulting from legal entity restructuring and the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by a $(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.
Liquidity and Capital Resources
OVERVIEW
Our company requires significant cash to support and grow our businesses. Our predominant source of cash is from our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.
We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the construction season.
We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):
|
| | | | | | |
| Financial Position Summary | 2019 | 2018 |
| Cash and cash equivalents | $ | 9,777 |
| $ | 20,776 |
|
| Restricted cash and equivalents | $ | 3,881 |
| $ | 3,369 |
|
| Notes payable | $ | 349,500 |
| $ | 185,620 |
|
| Short-term debt, including current maturities of long-term debt | $ | 5,743 |
| $ | 5,743 |
|
Long-term debt (a) | $ | 3,140,096 |
| $ | 2,950,835 |
|
| Stockholders’ equity | $ | 2,362,123 |
| $ | 2,181,588 |
|
| | | |
| Ratios | | |
| Long-term debt ratio | 57 | % | 57 | % |
| Total debt ratio | 60 | % | 59 | % |
______________
| |
| (a) | Carrying amount of long-term debt is net of deferred financing costs. |
Significant Factors Affecting Liquidity
Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including weather seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow. However, the potential for unforeseen events affecting cash needs will continue to exist.
Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At December 31, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.
Weather Seasonality, Commodity Pricing and Associated Hedging Strategies
We manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest expenserate movements and commodity price movements.
Utility Factors
Our cash flows, and in 2017turn liquidity needs in many of our regulated jurisdictions, can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and physical fixed price purchases.
Interest Rates
Some of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We do not have any interest rate swap agreements at December 31, 2019; 90% of our interest rate exposure has been mitigated through fixed interest rates.
Federal and State Regulations
We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
CASH GENERATION AND CASH REQUIREMENTS
Cash Generation
Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring in 2023, our CP Program, our ATM equity offering program and our ability to access the public and private capital markets through debt and equity securities offerings when necessary.
Cash Collateral
Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral with the counterparty to meet these obligations. The cash collateral we were required to post at December 31, 2019 was not material.
DEBT, EQUITY AND LIQUIDITY
Debt
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. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
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. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
|
| | | | | | | | | | | | | |
| | | Current | Short-term borrowings at | Letters of Credit at | Available Capacity at |
| Credit Facility | Expiration | Capacity | December 31, 2019 | December 31, 2019 | December 31, 2019 |
| Revolving Credit Facility and CP Program | July 30, 2023 | $ | 750 |
| $ | 350 |
| $ | 30 |
| $ | 370 |
|
The weighted average interest rate on short-term borrowings at December 31, 2019 was 2.03%. Short-term borrowing activity for the twelve months ended December 31, 2019 was:
|
| | | |
| | (dollars in millions) |
| Maximum amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 357 |
|
| Average amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 187 |
|
| Weighted average interest rates - short-term borrowing | 2.47 | % |
The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. We were in compliance with these covenants as of December 31, 2019. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.
Cross-Default Provisions
Our $7 million Corporate term loan contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to make timely payments of debt obligations or triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and the threshold principal amount is $50 million.
The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.
Utility Money Pool
As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates (2.210% at December 31, 2019). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
At December 31, 2019, money pool balances included (in thousands):
|
| | | |
| Subsidiary | Borrowings From Money Pool Outstanding |
| BHSC | $ | 148,041 |
|
| South Dakota Electric | 57,585 |
|
| Wyoming Electric | 37,993 |
|
| Total Money Pool borrowings from Parent | $ | 243,619 |
|
Equity
Shelf Registration
We have an effective automatic shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2020. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2019, we had approximately 61 million shares of common stock outstanding and no shares of preferred stock outstanding.
ATM
In 2019, we issued a total of 1,328,332 shares of common stock under the ATM for proceeds of $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled.
Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.
On January 29, 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:
|
| | | |
| | 2019 | 2018 | 2017 |
| Dividend Payout Ratio | 63% | 40% | 50% |
| Dividends Per Share | $2.05 | $1.93 | $1.81 |
Our three-year compound annualized dividend growth rate was 6.9% and all dividends were paid out of available operating cash flows.
Dividend Restrictions
As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither BHSC nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.
As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. See additional information in Note 6 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. See additional information in Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2019, we were in compliance with these covenants.
Financing Activities
Financing activities in 2019 consisted of the following:
We issued a total of 1.3 million shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.2 million in issuance costs.
On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029, and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, and repay a portion of short-term debt.
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continued to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.
Short-term borrowings from our Revolving Credit Facility and CP Program.
Future Financing Plans
We anticipate the following financing activities in 2020:
Renew our shelf registration and ATM;
Continued equity issuance under the ATM or assess other equity issuance options;
Refinance a portion of short-term borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and
Continue to assess debt and equity needs to support our capital expenditure plan.
CASH FLOW ACTIVITIES
The following table summarizes our cash flows (in thousands):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Cash provided by (used in) | | | |
| Operating activities | $ | 505,513 |
| $ | 488,811 |
| $ | 428,261 |
|
| Investing activities | $ | (816,210 | ) | $ | (465,849 | ) | $ | (317,118 | ) |
| Financing activities | $ | 300,210 |
| $ | (17,057 | ) | $ | (108,695 | ) |
2019 Compared to 2018
Operating Activities:
Net cash provided by operating activities was $17 million higher than in 2018. The variance to the prior year was primarily attributable to:
Cash earnings (income from continuing operations plus non-cash adjustments) were $37 million higher than prior year driven primarily by higher margins at our Electric and Gas Utilities;
Net outflows from operating assets and liabilities were $25 million higher than prior year, primarily attributable to:
Cash outflows increased by approximately $40 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of higher outside services, employee costs and other working capital requirements;
Cash inflows increased by approximately $59 million compared to 2016. Each period reflectsthe prior year primarily as a tax benefit. The effectiveresult of lower accounts receivable driven by lower pass-through revenues reflecting lower commodity prices; and
Cash inflows decreased by approximately $44 million primarily as a result of changes in our current regulatory liabilities due to the TCJA tax rate change that has subsequently been returned to customers and from changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity prices; and
Cash outflows decreased approximately $5.5 million due to the absence of operating activities of discontinued operations in 2019.
Investing Activities:
Net cash used in investing activities was $816 million in 2019, compared to net cash used in investing activities of $466 million in 2018 for 2016a variance of $350 million. This variance was impacted by a benefitprimarily due to:
Capital expenditures of approximately $5.8$818 million in 2019 compared to $458 million in 2018. The $361 million increase from the prior year was due to higher capital expenditures driven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities segments, the Corriedale Wind Energy Project at our Electric Utilities segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska, at our Electric Utilities segment, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, and construction of Busch Ranch II at our Power Generation segment; and
Net cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of our oil and gas segment.
Financing Activities:
Net cash provided by financing activities was $300 million in 2019 as compared to net cash used by financing activities of $17 million in 2018, an increase of $317 million due to the following:
Increase of $539 million due to issuances of long and short-term debt in excess of required maturities that were used to fund our capital program
Decrease of $199 million in common stock issued primarily due to prior year gross proceeds of approximately $299 million from additional percentage depletion deductions being claimed with respectthe Equity Unit conversion partially offset by current year net proceeds of $99 million through our ATM equity offering program;
Cash dividends on common stock of $125 million were paid in 2019 compared to a change$107 million paid in estimate2018; and
Cash outflows for tax purposes. Such deductions areother financing activities increased by approximately $5.5 million driven primarily the result of a changeby current year financing costs incurred in the applicationOctober 3, 2019 debt transaction.
CAPITAL EXPENDITURES
Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See Key Elements of our Business Strategy above in Item 7 - Executive Summary and Business Strategy for forecasted capital expenditure requirements.
A significant portion of our capital expenditures relates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and can be recovered from our utility customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.
Historical Capital Requirements
Our primary capital requirements for the three years ended December 31 were as follows (in thousands):
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
Property additions: (a) | | | | | |
Electric Utilities (b) | $ | 222,911 |
| | $ | 152,524 |
| | $ | 138,060 |
|
Gas Utilities (c) | 512,366 |
| | 288,438 |
| | 184,389 |
|
Power Generation (d) | 85,346 |
| | 30,945 |
| | 1,864 |
|
| Mining | 8,430 |
| | 18,794 |
| | 6,708 |
|
| Corporate and Other | 20,702 |
| | 11,723 |
| | 6,668 |
|
| Capital expenditures before discontinued operations | 849,755 |
| | 502,424 |
| | 337,689 |
|
| Discontinued operations | — |
| | 2,402 |
| | 23,222 |
|
| Total capital expenditures | 849,755 |
| | 504,826 |
| | 360,911 |
|
| Common stock dividends | 124,647 |
| | 106,591 |
| | 96,744 |
|
| Maturities/redemptions of long-term debt | 905,743 |
| | 854,743 |
| | 105,743 |
|
| Total capital requirements | $ | 1,880,145 |
| | $ | 1,466,160 |
| | $ | 563,398 |
|
____________________________
| |
| (a) | Includes accruals for property, plant and equipment as disclosed in Note 17 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
| |
| (b) | Current year capital expenditures at our Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Corriedale wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska. |
| |
| (c) | Current year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the 35-mile Natural Bridge pipeline project. |
| |
| (d) | Current year capital expenditures at our Power Generation segment increased due to construction of Busch Ranch II. |
CREDIT RATINGS AND COUNTERPARTIES
Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the maximum daily limitationCompany, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of 1,000 Bbls of oil equivalent allowed under the Internal Revenue Code.any other rating.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2019:
|
| | |
| Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a) | BBB+ | Stable |
Moody’s (b) | Baa2 | Stable |
Fitch (c) | BBB+ | Stable |
__________
| |
| (a) | On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook. |
| |
| (b) | On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook. |
| |
| (c) | On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook. |
Certain of our fees and our interest rates under various bank credit agreements are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgraded our senior unsecured debt, we will be required to pay higher fees and interest rates under these bank credit agreements.
The following table represents the credit ratings of South Dakota Electric at December 31, 2019:
|
| |
| Rating Agency | Senior Secured Rating |
S&P (a) | A |
Moody’s (b) | A1 |
Fitch (c) | A |
__________
| |
| (a) | On April 30, 2019, S&P affirmed A rating. |
| |
| (b) | On December 20, 2019, Moody’s affirmed A1 rating. |
| |
| (c) | On August 29, 2019, Fitch affirmed A rating. |
We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.
CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS
Contractual Obligations
In addition to our capital expenditure programs, we have contractual obligations and other commitments that will need to be funded in the future. The following information summarizes our cash obligations and commercial commitments at December 31, 2019. Actual future obligations may differ materially from these estimated amounts (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| Contractual Obligations | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total |
Long-term debt(a) | $ | 5,743 |
| $ | 8,435 |
| $ | — |
| $ | 525,000 |
| $ | 2,855 |
| $ | 2,635,000 |
| $ | 3,177,033 |
|
Interest payments (a) | 131,859 |
| 131,842 |
| 131,756 |
| 131,756 |
| 109,390 |
| 1,273,648 |
| 1,910,251 |
|
Unconditional purchase obligations(b) | 181,773 |
| 159,827 |
| 134,018 |
| 105,583 |
| 54,098 |
| 126,147 |
| 761,446 |
|
Lease obligations(c) | 1,144 |
| 991 |
| 869 |
| 844 |
| 724 |
| 2,009 |
| 6,581 |
|
AROs (d) | 330 |
| 231 |
| 144 |
| 33 |
| 9,362 |
| 54,105 |
| 64,205 |
|
Employee benefit plans(e) | 18,921 |
| 19,678 |
| 19,736 |
| 19,944 |
| 19,896 |
| 35,580 |
| 133,755 |
|
| CP Program | 349,500 |
| — |
| — |
| — |
| — |
| — |
| 349,500 |
|
Total contractual cash obligations(f) | $ | 689,270 |
| $ | 321,004 |
| $ | 286,523 |
| $ | 783,160 |
| $ | 196,325 |
| $ | 4,126,489 |
| $ | 6,402,771 |
|
__________
| |
| (a) | Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2019. |
| |
| (b) | 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 2019 and price assumptions using existing prices at December 31, 2019. Our transmission obligations are based on filed tariffs as of December 31, 2019. |
| |
| (c) | Includes leases associated with several office and operating facilities, communication tower sites, equipment and materials storage. |
| |
| (d) | Represents estimated payments for AROs associated with long-lived assets primarily related to retirement and reclamation of natural gas pipelines, mining sites, wind farms and an evaporation pond. See Notes 1 and 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. |
| |
| (e) | Represents estimated employer contributions to the Defined Benefit Pension Plan, the Non-Pension Defined Benefit Postretirement Healthcare Plan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2029 as discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
| |
| (f) | 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, 2019. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table; (3) our $4.2 million liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions as discussed in Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
Our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. In addition, a portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure, are carried out for 60 days. As of December 31, 2019, we are committed to purchase 3.7 million MMBtu, 3.7 million MMBtu, and 1.8 million MMBtu in each of the years from 2020 to 2022, respectively.
Off-Balance Sheet Commitments
We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit.
Guarantees
We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 20 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Letters of Credit
Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. For more information on these letters of credit, see Note 7 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Critical Accounting Policies Involving Significant Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments, or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Regulation
Our utility operationsregulated Electric and Gas Utilities are subject to cost-of-service regulation with respectand earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates service area, accounting,are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and various other matters by stateapproved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and federal regulatory authorities. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effects in the manner of which independent third-party regulators establish rates. Regulatory assets generally represent incurred or accrued costs that have been deferred when future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.allowed return on invested capital at any given time.
Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.
As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million, respectively, and total regulatory liabilities of $537 million and $541 million, respectively. See Note 13 of the Notes to the Consolidated Financial Statements for further information.
Goodwill
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.
Accounting standards for testing goodwill for impairment require a two-step process be performed to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. The first step of this test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss.
Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our 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. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation,calculation; 2) estimates of long-term growth rates for our businesses,businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate,rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2018.2019. Although 1% to 2% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews, as well as other improved efficiency and cost reduction initiatives. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting
unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.
The estimates and assumptions used in the impairment assessments are based on available market information and we believe they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. For the years ended December 31, 2019, 2018, 2017, and 2016,2017, there were no impairment losses recorded. At December 31, 2018,2019, the fair value substantially exceeded the carrying value at all reporting units.
As described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have prospectively adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, on January 1, 2020.
PensionLiquidity and Other Postretirement BenefitsCapital Resources
OVERVIEW
Our company requires significant cash to support and grow our businesses. Our predominant source of cash is from our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.
We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the construction season.
We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):
|
| | | | | | |
| Financial Position Summary | 2019 | 2018 |
| Cash and cash equivalents | $ | 9,777 |
| $ | 20,776 |
|
| Restricted cash and equivalents | $ | 3,881 |
| $ | 3,369 |
|
| Notes payable | $ | 349,500 |
| $ | 185,620 |
|
| Short-term debt, including current maturities of long-term debt | $ | 5,743 |
| $ | 5,743 |
|
Long-term debt (a) | $ | 3,140,096 |
| $ | 2,950,835 |
|
| Stockholders’ equity | $ | 2,362,123 |
| $ | 2,181,588 |
|
| | | |
| Ratios | | |
| Long-term debt ratio | 57 | % | 57 | % |
| Total debt ratio | 60 | % | 59 | % |
______________
| |
| (a) | Carrying amount of long-term debt is net of deferred financing costs. |
Significant Factors Affecting Liquidity
Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including weather seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow. However, the potential for unforeseen events affecting cash needs will continue to exist.
Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At December 31, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.
Weather Seasonality, Commodity Pricing and Associated Hedging Strategies
We manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest rate movements and commodity price movements.
Utility Factors
Our cash flows, and in turn liquidity needs in many of our regulated jurisdictions, can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and physical fixed price purchases.
Interest Rates
Some of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We do not have any interest rate swap agreements at December 31, 2019; 90% of our interest rate exposure has been mitigated through fixed interest rates.
Federal and State Regulations
We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
CASH GENERATION AND CASH REQUIREMENTS
Cash Generation
Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring in 2023, our CP Program, our ATM equity offering program and our ability to access the public and private capital markets through debt and equity securities offerings when necessary.
Cash Collateral
Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral with the counterparty to meet these obligations. The cash collateral we were required to post at December 31, 2019 was not material.
DEBT, EQUITY AND LIQUIDITY
Debt
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. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
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. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
|
| | | | | | | | | | | | | |
| | | Current | Short-term borrowings at | Letters of Credit at | Available Capacity at |
| Credit Facility | Expiration | Capacity | December 31, 2019 | December 31, 2019 | December 31, 2019 |
| Revolving Credit Facility and CP Program | July 30, 2023 | $ | 750 |
| $ | 350 |
| $ | 30 |
| $ | 370 |
|
The weighted average interest rate on short-term borrowings at December 31, 2019 was 2.03%. Short-term borrowing activity for the twelve months ended December 31, 2019 was:
|
| | | |
| | (dollars in millions) |
| Maximum amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 357 |
|
| Average amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 187 |
|
| Weighted average interest rates - short-term borrowing | 2.47 | % |
The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. We were in compliance with these covenants as of December 31, 2019. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.
Cross-Default Provisions
Our $7 million Corporate term loan contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to make timely payments of debt obligations or triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and the threshold principal amount is $50 million.
The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.
Utility Money Pool
As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates (2.210% at December 31, 2019). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
At December 31, 2019, money pool balances included (in thousands):
|
| | | |
| Subsidiary | Borrowings From Money Pool Outstanding |
| BHSC | $ | 148,041 |
|
| South Dakota Electric | 57,585 |
|
| Wyoming Electric | 37,993 |
|
| Total Money Pool borrowings from Parent | $ | 243,619 |
|
Equity
Shelf Registration
We have an effective automatic shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2020. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2019, we had approximately 61 million shares of common stock outstanding and no shares of preferred stock outstanding.
ATM
In 2019, we issued a total of 1,328,332 shares of common stock under the ATM for proceeds of $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled.
Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.
On January 29, 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:
|
| | | |
| | 2019 | 2018 | 2017 |
| Dividend Payout Ratio | 63% | 40% | 50% |
| Dividends Per Share | $2.05 | $1.93 | $1.81 |
Our three-year compound annualized dividend growth rate was 6.9% and all dividends were paid out of available operating cash flows.
Dividend Restrictions
As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither BHSC nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.
As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. See additional information in Note 6 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. See additional information in Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2019, we were in compliance with these covenants.
Financing Activities
Financing activities in 2019 consisted of the following:
We issued a total of 1.3 million shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.2 million in issuance costs.
On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029, and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, and repay a portion of short-term debt.
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continued to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.
Short-term borrowings from our Revolving Credit Facility and CP Program.
Future Financing Plans
We anticipate the following financing activities in 2020:
Renew our shelf registration and ATM;
Continued equity issuance under the ATM or assess other equity issuance options;
Refinance a portion of short-term borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and
Continue to assess debt and equity needs to support our capital expenditure plan.
CASH FLOW ACTIVITIES
The following table summarizes our cash flows (in thousands):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Cash provided by (used in) | | | |
| Operating activities | $ | 505,513 |
| $ | 488,811 |
| $ | 428,261 |
|
| Investing activities | $ | (816,210 | ) | $ | (465,849 | ) | $ | (317,118 | ) |
| Financing activities | $ | 300,210 |
| $ | (17,057 | ) | $ | (108,695 | ) |
2019 Compared to 2018
Operating Activities:
Net cash provided by operating activities was $17 million higher than in 2018. The variance to the prior year was primarily attributable to:
Cash earnings (income from continuing operations plus non-cash adjustments) were $37 million higher than prior year driven primarily by higher margins at our Electric and Gas Utilities;
Net outflows from operating assets and liabilities were $25 million higher than prior year, primarily attributable to:
Cash outflows increased by approximately $40 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of higher outside services, employee costs and other working capital requirements;
Cash inflows increased by approximately $59 million compared to the prior year primarily as a result of lower accounts receivable driven by lower pass-through revenues reflecting lower commodity prices; and
Cash inflows decreased by approximately $44 million primarily as a result of changes in our current regulatory liabilities due to the TCJA tax rate change that has subsequently been returned to customers and from changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity prices; and
Cash outflows decreased approximately $5.5 million due to the absence of operating activities of discontinued operations in 2019.
Investing Activities:
Net cash used in investing activities was $816 million in 2019, compared to net cash used in investing activities of $466 million in 2018 for a variance of $350 million. This variance was primarily due to:
Capital expenditures of approximately $818 million in 2019 compared to $458 million in 2018. The $361 million increase from the prior year was due to higher capital expenditures driven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities segments, the Corriedale Wind Energy Project at our Electric Utilities segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska, at our Electric Utilities segment, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, and construction of Busch Ranch II at our Power Generation segment; and
Net cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of our oil and gas segment.
Financing Activities:
Net cash provided by financing activities was $300 million in 2019 as compared to net cash used by financing activities of $17 million in 2018, an increase of $317 million due to the following:
Increase of $539 million due to issuances of long and short-term debt in excess of required maturities that were used to fund our capital program
Decrease of $199 million in common stock issued primarily due to prior year gross proceeds of approximately $299 million from the Equity Unit conversion partially offset by current year net proceeds of $99 million through our ATM equity offering program;
Cash dividends on common stock of $125 million were paid in 2019 compared to $107 million paid in 2018; and
Cash outflows for other financing activities increased by approximately $5.5 million driven primarily by current year financing costs incurred in the October 3, 2019 debt transaction.
CAPITAL EXPENDITURES
Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See Key Elements of our Business Strategy above in Item 7 - Executive Summary and Business Strategy for forecasted capital expenditure requirements.
A significant portion of our capital expenditures relates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and can be recovered from our utility customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.
Historical Capital Requirements
Our primary capital requirements for the three years ended December 31 were as follows (in thousands):
|
| | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 |
Property additions: (a) | | | | | |
Electric Utilities (b) | $ | 222,911 |
| | $ | 152,524 |
| | $ | 138,060 |
|
Gas Utilities (c) | 512,366 |
| | 288,438 |
| | 184,389 |
|
Power Generation (d) | 85,346 |
| | 30,945 |
| | 1,864 |
|
| Mining | 8,430 |
| | 18,794 |
| | 6,708 |
|
| Corporate and Other | 20,702 |
| | 11,723 |
| | 6,668 |
|
| Capital expenditures before discontinued operations | 849,755 |
| | 502,424 |
| | 337,689 |
|
| Discontinued operations | — |
| | 2,402 |
| | 23,222 |
|
| Total capital expenditures | 849,755 |
| | 504,826 |
| | 360,911 |
|
| Common stock dividends | 124,647 |
| | 106,591 |
| | 96,744 |
|
| Maturities/redemptions of long-term debt | 905,743 |
| | 854,743 |
| | 105,743 |
|
| Total capital requirements | $ | 1,880,145 |
| | $ | 1,466,160 |
| | $ | 563,398 |
|
____________________________
| |
| (a) | Includes accruals for property, plant and equipment as disclosed in Note 17 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
| |
| (b) | Current year capital expenditures at our Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Corriedale wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska. |
| |
| (c) | Current year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the 35-mile Natural Bridge pipeline project. |
| |
| (d) | Current year capital expenditures at our Power Generation segment increased due to construction of Busch Ranch II. |
CREDIT RATINGS AND COUNTERPARTIES
Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2019:
|
| | |
| Rating Agency | Senior Unsecured Rating | Outlook |
S&P (a) | BBB+ | Stable |
Moody’s (b) | Baa2 | Stable |
Fitch (c) | BBB+ | Stable |
__________
| |
| (a) | On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook. |
| |
| (b) | On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook. |
| |
| (c) | On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook. |
Certain of our fees and our interest rates under various bank credit agreements are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgraded our senior unsecured debt, we will be required to pay higher fees and interest rates under these bank credit agreements.
The following table represents the credit ratings of South Dakota Electric at December 31, 2019:
|
| |
| Rating Agency | Senior Secured Rating |
S&P (a) | A |
Moody’s (b) | A1 |
Fitch (c) | A |
__________
| |
| (a) | On April 30, 2019, S&P affirmed A rating. |
| |
| (b) | On December 20, 2019, Moody’s affirmed A1 rating. |
| |
| (c) | On August 29, 2019, Fitch affirmed A rating. |
We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.
CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS
Contractual Obligations
In addition to our capital expenditure programs, we have contractual obligations and other commitments that will need to be funded in the future. The following information summarizes our cash obligations and commercial commitments at December 31, 2019. Actual future obligations may differ materially from these estimated amounts (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| Contractual Obligations | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total |
Long-term debt(a) | $ | 5,743 |
| $ | 8,435 |
| $ | — |
| $ | 525,000 |
| $ | 2,855 |
| $ | 2,635,000 |
| $ | 3,177,033 |
|
Interest payments (a) | 131,859 |
| 131,842 |
| 131,756 |
| 131,756 |
| 109,390 |
| 1,273,648 |
| 1,910,251 |
|
Unconditional purchase obligations(b) | 181,773 |
| 159,827 |
| 134,018 |
| 105,583 |
| 54,098 |
| 126,147 |
| 761,446 |
|
Lease obligations(c) | 1,144 |
| 991 |
| 869 |
| 844 |
| 724 |
| 2,009 |
| 6,581 |
|
AROs (d) | 330 |
| 231 |
| 144 |
| 33 |
| 9,362 |
| 54,105 |
| 64,205 |
|
Employee benefit plans(e) | 18,921 |
| 19,678 |
| 19,736 |
| 19,944 |
| 19,896 |
| 35,580 |
| 133,755 |
|
| CP Program | 349,500 |
| — |
| — |
| — |
| — |
| — |
| 349,500 |
|
Total contractual cash obligations(f) | $ | 689,270 |
| $ | 321,004 |
| $ | 286,523 |
| $ | 783,160 |
| $ | 196,325 |
| $ | 4,126,489 |
| $ | 6,402,771 |
|
__________
| |
| (a) | Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2019. |
| |
| (b) | 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 2019 and price assumptions using existing prices at December 31, 2019. Our transmission obligations are based on filed tariffs as of December 31, 2019. |
| |
| (c) | Includes leases associated with several office and operating facilities, communication tower sites, equipment and materials storage. |
| |
| (d) | Represents estimated payments for AROs associated with long-lived assets primarily related to retirement and reclamation of natural gas pipelines, mining sites, wind farms and an evaporation pond. See Notes 1 and 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. |
| |
| (e) | Represents estimated employer contributions to the Defined Benefit Pension Plan, the Non-Pension Defined Benefit Postretirement Healthcare Plan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2029 as discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
| |
| (f) | 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, 2019. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table; (3) our $4.2 million liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions as discussed in Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
Our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. In addition, a portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure, are carried out for 60 days. As of December 31, 2019, we are committed to purchase 3.7 million MMBtu, 3.7 million MMBtu, and 1.8 million MMBtu in each of the years from 2020 to 2022, respectively.
Off-Balance Sheet Commitments
We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit.
Guarantees
We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 20 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Letters of Credit
Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. For more information on these letters of credit, see Note 7 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Critical Accounting Policies Involving Significant Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments, or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Regulation
Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.
Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.
As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million, respectively, and total regulatory liabilities of $537 million and $541 million, respectively. See Note 13 of the Notes to the Consolidated Financial Statements for further information.
Goodwill
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.
Accounting standards for testing goodwill for impairment require a two-step process be performed to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. The first step of this test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss.
Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our 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. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2019. Although 1% to 2% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews, as well as other improved efficiency and cost reduction initiatives. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.
The estimates and assumptions used in the impairment assessments are based on available market information and we believe they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. For the years ended December 31, 2019, 2018, and 2017, there were no impairment losses recorded. At December 31, 2019, the fair value substantially exceeded the carrying value at all reporting units.
As described in Note 181 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, and several defined post-retirement healthcare plans and non-qualified retirement plans. A Master Trust holdsprospectively adopted ASU 2017-04, Simplifying the assetsTest for the pension plan. Trusts for the funded portion of the post-retirement healthcare plans have also been established.Goodwill Impairment, on January 1, 2020.
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.
The pension benefit cost for 2019 for our non-contributory funded pension plan is expected to be $2.1 million compared to $6.3 million in 2018. The decrease in pension benefit cost is driven primarily by an increase in the discount rate.
The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:
|
| | | | |
| | 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. |
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain acquired subsidiaries file as a separate consolidated group. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.
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%. The Company uses 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.
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, financial position, or cash flows.
The Company has revalued the deferred income taxes at the 21% federal tax rate as of December 31, 2017 and as a result, 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. As of December 31, 2018 we have a regulatory liability associated with TCJA related items of $311 million, completing the revaluation of deferred taxes pursuant to the TCJA. A significant portion 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 regulatory liability associated with TCJA related items. 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.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.
See Note 15 in the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
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. Pertaining to our 2016 acquisition of SourceGas, 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.
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 in the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Accounting for Oil and Gas Activities
We completed the divestiture of our Oil and Gas segment in 2018. For 2016, our Oil and Gas Activities were significant. Accounting for oil and gas activities in 2017 and 2016 was a significant accounting policy and included significant accounting estimates as disclosed below.
Impairment testing of assets held for sale
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. For the assets that have not yet been sold, the estimated fair value of our oil and gas assets was determined using the market approach. The market
approach was based on the fourth quarter 2017 sale of our Powder River Basin assets and other sale transactions of our other properties.
There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are 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. For additional information, see Note 21 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Full Cost Method of Accounting for Oil and Gas Activities
Prior to the November 1, 2017 decision to divest our oil and gas business, we accounted for oil and gas activities under the full cost method of accounting, whereby all productive and nonproductive costs related to acquisition, exploration, development, abandonment and reclamation activities were capitalized. Accounting for oil and gas activities is subject to industry-specific rules. 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 abandonments of properties, are generally treated as adjustments to the cost of the properties with no gain or loss recognized. Net capitalized costs are subject to a ceiling test that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. This method values the reserves based upon SEC-defined prices for oil and gas as of the end of each reporting period adjusted for contracted price changes. The prices, as well as costs and development capital, are assumed to remain constant for the remaining life of the properties. If the net capitalized costs exceed the full-cost ceiling, then a permanent non-cash write-down is required to be charged to earnings in that reporting period. Under these SEC-defined product prices, our net capitalized costs were more than the full cost ceiling throughout 2016, which required an after-tax write-down of $58 million for the year ended December 31, 2016. Reserves in 2016 were determined consistent with SEC requirements using a 12-month average 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 adjusted for contracted price changes.
Oil, Natural Gas, and Natural Gas Liquids Reserve Estimates
Estimates of our proved crude oil, natural gas and NGL reserves are based on the quantities of each that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prior to November 1, 2017, an independent petroleum engineering company prepared reports that estimate our proved oil, natural gas and NGL reserves annually. The accuracy of any crude oil, natural gas and NGL reserve estimate is a function of the quality of available data, engineering judgment and geological interpretation. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and work-over costs, all of which may in fact vary considerably from actual results. In addition, as crude oil, natural gas and NGL prices and cost levels change from year to year, the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves.
Estimates for our crude oil, natural gas, and NGL reserves are used throughout our financial statements. For example, since we used the unit-of-production method of calculating depletion expense, the amortization rate of our capitalized oil and gas properties incorporated the estimated unit-of-production attributable to the estimates of proved reserves. Under full-cost accounting, the net book value of our crude oil and gas properties was also subject to a “ceiling” limitation based in large part on the value of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.
Liquidity and Capital Resources
OVERVIEW
Our company requires significant cash to support and grow our businesses. Our predominant source of cash is supplied byfrom our operations and supplemented with corporate financings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate. As discussed in more detail below under income taxes, we experienced an increase in working capital requirements as a result of complying with the TCJA and the impact of providing TCJA benefits to customers.
The most significant uses of cash are for our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, as well as the payment of dividends to our shareholders. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the summer construction season.
We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):
| | | Financial Position Summary | 2018 | 2017 | 2019 | 2018 |
| Cash and cash equivalents | $ | 20,776 |
| $ | 15,420 |
| $ | 9,777 |
| $ | 20,776 |
|
| Restricted cash and equivalents | $ | 3,369 |
| $ | 2,820 |
| $ | 3,881 |
| $ | 3,369 |
|
| Notes payable | $ | 185,620 |
| $ | 211,300 |
| $ | 349,500 |
| $ | 185,620 |
|
| Short-term debt, including current maturities of long-term debt | $ | 5,743 |
| $ | 5,743 |
| $ | 5,743 |
| $ | 5,743 |
|
Long-term debt (a) | $ | 2,950,835 |
| $ | 3,109,400 |
| $ | 3,140,096 |
| $ | 2,950,835 |
|
| Stockholders’ equity | $ | 2,181,588 |
| $ | 1,708,974 |
| $ | 2,362,123 |
| $ | 2,181,588 |
|
| | | |
| Ratios | | |
| Long-term debt ratio | 57 | % | 64 | % | 57 | % | 57 | % |
| Total debt ratio | 59 | % | 66 | % | 60 | % | 59 | % |
______________
| |
| (a) | Carrying amount of long-term debt is net of deferred financing costs. |
Significant Factors Affecting Liquidity
Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including weather seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow. However, the potential for unforeseen events affecting cash needs will continue to exist.
Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At December 31, 2018,2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.
Weather Seasonality, Commodity Pricing and Associated Hedging Strategies
We manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest rate movements and commodity price movements.
Utility Factors
Our cash flows, and in turn liquidity needs in many of our regulated jurisdictions, can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging of approximately 40% to 70%a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and basis swaps.physical fixed price purchases.
Interest Rates
SeveralSome of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We don’tdo not have any interest rate swap agreements at December 31, 20182019; 84%90% of our interest rate exposure has been mitigated through fixed interest rates.
Federal and State Regulations
Federal
We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
Income Tax
The TCJA required revaluation of federal deferred tax assets and liabilities using the new lower corporate tax rate of 21%.
We have reached agreements with regulators in six states and are working with regulators in our seventh state, as well as FERC. Our working capital requirements increased as a result of complying with the TCJA and providing the benefits of the TCJA to customers, negatively impacted our cash flows by approximately $40 million to $45 million annually for the next several years. See Notes 1 and 13 for more information on regulatory matters and Note 15 for revaluations of deferred taxes under the TCJA.
Acceleration of depreciation for tax purposes, including 50% bonus depreciation, was previously available for certain property placed in service through September 27, 2017. The TCJA enacted 100% bonus depreciation generally to qualifying property acquired and placed in service after September 27, 2017 and before January 1, 2023. After 2022, bonus depreciation would reduce 20% per year for qualifying property placed in service through 2026. The provision expands the property that is eligible for this immediate expensing by repealing the requirement that the original use of the property begin with the taxpayer. Instead, the property is eligible for the additional depreciation if it is the taxpayer’s first use. Under the provision, qualified property eligible for bonus depreciation, including immediate expensing, does not include any property used by a regulated public utility company or any property used in a real property trade or business. These depreciation provisions resulted in cash tax benefits for BHC as indicated in the table below:
|
| | | |
| (in millions) | 2018 | 2017 | 2016 |
| Tax benefit | $— | $37 | $81 |
In addition, bonus depreciation will apply to qualifying property whose construction and completion period encompasses multiple tax years. The exception being with respect to costs that would be incurred in 2027 when, under current law, bonus depreciation is scheduled to expire.
The effect of additional depreciation deductions as a result of bonus depreciation will serve to reduce taxable income and contribute to extending the tax loss carryforwards from being fully utilized until 2022 based on current projections.
See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
CASH GENERATION AND CASH REQUIREMENTS
Cash Generation
Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring in 2023, our CP Program, our ATM equity offering program and our ability to access the public and private capital markets through debt and equity securities offerings when necessary.
Cash Collateral
Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral with the counterparty to meet these obligations.
We have posted the following amounts of The cash collateral with counterpartieswe were required to post at December 31, (in thousands):2019 was not material.
|
| | | | | | |
| 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 |
|
DEBT, EQUITY AND LIQUIDITY
Financing Transactions and Short-Term LiquidityDebt
Our principal liquidity sources to meet day-to-day operating cash requirements are cash from operations, our CP Program and our corporate Revolving Credit Facility.
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.
See
Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
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.
See
Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
| | | | | Current | Revolver Borrowings at | CP Program Borrowings at | Letters of Credit at | Available Capacity at | | Current | Short-term borrowings at | Letters of Credit at | Available Capacity at |
| Credit Facility | Expiration | Capacity | December 31, 2018 | December 31, 2018 | Expiration | Capacity | December 31, 2019 | December 31, 2019 |
| Revolving Credit Facility | July 30, 2023 | $ | 750 |
| $ | — |
| $ | 186 |
| $ | 22 |
| $ | 542 |
| |
| Revolving Credit Facility and CP Program | | July 30, 2023 | $ | 750 |
| $ | 350 |
| $ | 30 |
| $ | 370 |
|
The weighted average interest rate on CP Programshort-term borrowings at December 31, 20182019 was 2.88%2.03%. Revolving Credit Facility and CP Program financingShort-term borrowing activity for the twelve months ended December 31, 20182019 was:
|
| | | |
| | (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 | — | % |
|
| | | |
| | (dollars in millions) |
| Maximum amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 357 |
|
| Average amount outstanding - short-term borrowing (based on daily outstanding balances) | $ | 187 |
|
| Weighted average interest rates - short-term borrowing | 2.47 | % |
____________________________
| |
(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. |
The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. Under the Revolving Credit Facility, 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 is Consolidated Indebtedness plus Consolidated Net Worth (which excludes noncontrolling interests in subsidiaries). Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of December 31, 2018.2019. See Note 7 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.
The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.
Capital ResourcesCross-Default Provisions
Our $7 million Corporate term loan contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to make timely payments of debt obligations or triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and the threshold principal amount is $50 million.
The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.
Utility Money Pool
As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates (2.210% at December 31, 2019). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
At December 31, 2019, money pool balances included (in thousands):
|
| | | |
| Subsidiary | Borrowings From Money Pool Outstanding |
| BHSC | $ | 148,041 |
|
| South Dakota Electric | 57,585 |
|
| Wyoming Electric | 37,993 |
|
| Total Money Pool borrowings from Parent | $ | 243,619 |
|
Equity
Shelf Registration
We have an effective automatic shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2020. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2019, we had approximately 61 million shares of common stock outstanding and no shares of preferred stock outstanding.
ATM
In 2019, we issued a total of 1,328,332 shares of common stock under the ATM for proceeds of $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled.
Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.
On January 29, 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:
|
| | | |
| | 2019 | 2018 | 2017 |
| Dividend Payout Ratio | 63% | 40% | 50% |
| Dividends Per Share | $2.05 | $1.93 | $1.81 |
Our principal sources forthree-year compound annualized dividend growth rate was 6.9% and all dividends were paid out of available operating cash flows.
Dividend Restrictions
As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our long-term capital needsliquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska have been issuancesregulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of long-term debt securities bya dividend would reduce their equity ratio to below 40% of their total capitalization; and neither BHSC nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and itsupon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries alongmay generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.
As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. See additional information in Note 6 of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with proceeds obtained from public and private offeringscertain financial or other covenants. See additional information in Note 7 of equity and proceeds from our ATM equity offering program.Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2019, we were in compliance with these covenants.
Financing Activities
Financing activities in 20182019 consisted of the following:
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 settlementWe issued a total 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 6.3721.3 million shares of common stock. See Note 12stock under the ATM equity offering program for more information.proceeds of $99 million, net of $1.2 million in issuance costs.
On August 17, 2018,October 3, 2019, we completed a public debt offering of $400$700 million principal amount 4.350%in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due 2033. The proceedsOctober 15, 2029, and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $299$400 million principal amountCorporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, and repay a portion 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,June 17, 2019, we amended and restated our unsecuredCorporate term loan due August 2019.July 30, 2020. This amended and restated term loan, withamendment increased total commitments to $400 million from $300 million, outstanding at December 31, 2018, will now mature July 30, 2020extended the term through June 17, 2021 and hascontinued to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. See Note 6 for more information.The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.
We did not issue any shares of common stock under our ATM equity offering program in 2018.
Financing activities for 2017 consisted of short-termShort-term borrowings from our Revolving Credit Facility and CP Program. We also made principal payments of $50 million each on May 16, 2017 and July 17, 2017 on our Corporate term loan due August 9, 2019. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan. On August 4, 2017, we renewed the ATM equity offering program which reset the size of the ATM equity offering program to an aggregate value of up to $300 million. We did not issue any shares of common stock under our ATM equity offering program during 2017.
Future Financing Plans
We will evaluate refinancing options foranticipate the following financing activities in 2020:
Renew our $200 million senior notes due July 15, 2020shelf registration and ATM;
Continued equity issuance under the $300 million Corporate term loan due July 30, 2020.ATM or assess other equity issuance options;
Cross-Default Provisions
Our $300 million and $13 million Corporate term loans contain cross-default provisions that could result inRefinance a default under such agreements if BHC or its material subsidiaries failed to make timely paymentsportion of debt obligations or triggered other default provisions under any debt agreement totaling, inshort-term borrowings held through the aggregate principal amount of $50 million or more that permits the acceleration of debt maturities or mandatory debt prepayment. Our Revolving Credit Facility contains the same provisions and a threshold principal amount is $50 million.CP Program to long-term debt; and
The Revolving Credit Facility prohibits us from paying cash dividends if we are in default or if paying dividends would cause usContinue to be in default.assess debt and equity needs to support our capital expenditure plan.
Equity
Based on our current disclosed capital spending forecast, we anticipate the need for issuing $25 million to $50 million of equity annually, in 2019 and 2020 under our ATM equity offering program. Aside from our ATM equity offering program, we do not anticipate any other need to further access the equity capital markets in the next three years.
Shelf Registration
We have an effective automatic shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. We renewed our shelf registration on August 4, 2017. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2018, we had approximately 60 million shares of common stock outstanding and no shares of preferred stock outstanding.
Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.
On January 30, 2019, our Board of Directors declared a quarterly dividend of $0.505 per share or an annualized equivalent dividend rate of $2.02 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:
|
| | | |
| | 2018 | 2017 | 2016 |
| Dividend Payout Ratio | 40% | 50% | 65% |
| Dividends Per Share | $1.93 | $1.81 | $1.68 |
Our three-year compound annualized dividend growth rate was 6.0% and all dividends were paid out of available operating cash flows.
Dividend Restrictions
As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.
As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. See additional information in Note 6 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. See additional information in Note 7 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2018, we were in compliance with these covenants.
Utility Money Pool
As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates (3.056% and 1.962% at December 31, 2018 and 2017, respectively). While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
At December 31, money pool balances included (in thousands):
|
| | | | | | |
| | 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 |
|
CASH FLOW ACTIVITIES
The following table summarizes our cash flows (in thousands):
| | | | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| Cash provided by (used in) | | |
| Operating activities | $ | 488,811 |
| $ | 428,261 |
| $ | 320,479 |
| $ | 505,513 |
| $ | 488,811 |
| $ | 428,261 |
|
| Investing activities | $ | (465,849 | ) | $ | (317,118 | ) | $ | (1,588,165 | ) | $ | (816,210 | ) | $ | (465,849 | ) | $ | (317,118 | ) |
| Financing activities | $ | (17,057 | ) | $ | (108,695 | ) | $ | 840,998 |
| $ | 300,210 |
| $ | (17,057 | ) | $ | (108,695 | ) |
20182019 Compared to 20172018
Operating Activities:
Net cash provided by operating activities was $61$17 million higher than in 2017.2018. The variance to the prior year was primarily attributable to:
Cash earnings (income from continuing operations plus non-cash adjustments) were $7$37 million lowerhigher than prior year driven primarily by impacts of customer refunds related to the TCJA tax decrease which lowered current year revenue;higher margins at our Electric and Gas Utilities;
Net inflowoutflows from operating assets and liabilities was $62were $25 million higher than prior year, primarily attributable to:
Cash inflowsoutflows increased by approximately $34$40 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;higher outside services, employee costs and other working capital requirements;
Cash outflowsinflows increased by approximately $43$59 million compared to the prior year primarily as a result of higherlower accounts receivable driven by higherlower pass-through revenues energy delivered and energyreflecting lower commodity prices; and
Cash inflows increaseddecreased by approximately $72$44 million primarily as a result of changes in our current regulatory liabilities due to the TCJA tax rate change that has subsequently been returned to customers and from changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity price on our regulatory assetsprices; 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$5.5 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 expirationabsence of accrued contract payables related to Equity Units; and
Cash outflows increased approximately $25 million due to operating activities of discontinued operations.operations in 2019.
Investing Activities:
Net cash used in investing activities was $466$816 million in 2018,2019, compared to net cash used in investing activities of $317$466 million in 20172018 for a variance of $149$350 million. This variance was primarily due to:
Capital expenditures of approximately $818 million in 2019 compared to $458 million in 2018 compared to $326 million in 2017.2018. The $132$361 million increase from the prior year was due to higher capital expenditures driven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities which included additionalsegments, the Corriedale Wind Energy Project at our Electric Utilities segment, construction of the final segment of the 175-mile transmission investments, and higher programmatic integrity capitalline from Rapid City, South Dakota, to Stegall, Nebraska, at our Electric Utilities segment, the 35-mile Natural Bridge pipeline project at our Gas Utilities. Capital expenditures increasedUtilities segment, and construction of Busch Ranch II at our Power Generation segment due to the Busch Ranch I purchase,segment; 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.
Financing Activities:
Net cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of our oil and gas segment.
Financing Activities:
Net cash provided by financing activities was $300 million in 2019 as compared to net cash used by financing activities of $17 million in 2018, a decreasean increase of $92$317 million from 2017 primarily due to the following:
PaymentsIncrease of long-term debt increased by $749$539 million due to current year payments on the $300issuances of long and short-term debt in excess of required maturities that were used to fund our capital program
Decrease of $199 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 millioncommon stock issued primarily 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;
Grossprior year 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;partially offset by current year net proceeds of $99 million through our ATM equity offering program;
Cash dividends on common stock of $107$125 million were paid in 20182019 compared to $97$107 million paid in 2017;2018; and
Cash outflows for other financing activities increased by approximately $4.3$5.5 million driven primarily by highercurrent year financing costs incurred in the July 30, 2018 and August 17, 2018October 3, 2019 debt transactions.transaction.
2017 Compared to 2016
Operating Activities:
Net cash provided by operating activities was $108 million higher than in 2016. The variance to the prior year was primarily attributable to:
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.
Investing Activities:
Net cash used in investing activities was $317 million in 2017, compared to net cash used in investing activities of $1.6 billion in 2016 for a variance of $1.3 billion. This variance was primarily due to:
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.
Financing Activities:
Net cash used in financing activities was $109 million in 2017, an increase of $950 million from 2016 primarily due to the following:
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.
CAPITAL EXPENDITURES
Historically, aA significant portion of our capital expenditures relate primarilyrelates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and if considered prudent by regulators, can be recovered from our utility customers.customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate and are subject to rate agreements. During 2018, our Electric Utilities’ capital expenditures included improvements to generating stations, transmission and distribution lines. Capital expenditures associated with our Gas Utilities are primarily to improve or expand the existing gas distribution network. In 2018, we also added renewable generation at our Power Generation segment, and upgraded equipment at our Mining segment. We believe that cash generated from operations, borrowings on our CP Program and Revolving Credit Facility, and equity issuances under our ATM equity offering program, if necessary, will be adequate to fund ongoing capital expenditures.operate.
Historical Capital Requirements
Our primary capital requirements for the three years ended December 31 were as follows (in thousands):
| | | | 2018 | | 2017 | | 2016 | 2019 | | 2018 | | 2017 |
Property additions: (a) | | | | | | | | | | |
Electric Utilities | $ | 152,524 |
| | $ | 138,060 |
| | $ | 258,739 |
| $ | 222,911 |
| | $ | 152,524 |
| | $ | 138,060 |
|
Gas Utilities | 288,438 |
| | 184,389 |
| | 173,930 |
| 512,366 |
| | 288,438 |
| | 184,389 |
|
Power Generation | 30,945 |
| | 1,864 |
| | 4,719 |
| 85,346 |
| | 30,945 |
| | 1,864 |
|
| Mining | 18,794 |
| | 6,708 |
| | 5,709 |
| 8,430 |
| | 18,794 |
| | 6,708 |
|
| Corporate and Other | 11,723 |
| | 6,668 |
| | 17,353 |
| 20,702 |
| | 11,723 |
| | 6,668 |
|
| Capital expenditures before discontinued operations | 502,424 |
| | 337,689 |
| | 460,450 |
| 849,755 |
| | 502,424 |
| | 337,689 |
|
| Discontinued operations | 2,402 |
| | 23,222 |
| | 6,669 |
| — |
| | 2,402 |
| | 23,222 |
|
| Total capital expenditures | 504,826 |
| | 360,911 |
| | 467,119 |
| 849,755 |
| | 504,826 |
| | 360,911 |
|
| Common stock dividends | 106,591 |
| | 96,744 |
| | 87,570 |
| 124,647 |
| | 106,591 |
| | 96,744 |
|
| Maturities/redemptions of long-term debt | 854,743 |
| | 105,743 |
| | 1,164,308 |
| 905,743 |
| | 854,743 |
| | 105,743 |
|
| Total capital requirements | $ | 1,466,160 |
| | $ | 563,398 |
| | $ | 1,718,997 |
| $ | 1,880,145 |
| | $ | 1,466,160 |
| | $ | 563,398 |
|
____________________________
| |
| (a) | Includes accruals for property, plant and equipment.equipment as disclosed in Note 17 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
| |
| (b) | Current year capital expenditures at our Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Corriedale wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska. |
| |
| (c) | Current year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the 35-mile Natural Bridge pipeline project. |
| |
| (d) | Current year capital expenditures at our Power Generation segment increased due to construction of Busch Ranch II. |
CREDIT RATINGS AND COUNTERPARTIES
Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. The inabilityIn order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms could negatively affect the Company’s ability to maintain or expand its businesses.terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. BHC notes that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 20182019:
|
| | |
| 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,February 28, 2019, S&P upgraded toaffirmed our BBB+ rating and revised the outlook to Stable.maintained a Stable outlook. |
| |
| (b) | On December 12, 2018, Moody's20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook. outlook. |
| |
| (c) | On October 11, 2018,August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook. |
Certain of our fees and our interest rates under various bank credit agreements are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgraded our senior unsecured debt, we will be required to pay higher fees and interest rates under these bank credit agreements.
The following table represents the credit ratings of South Dakota Electric at December 31, 20182019:
|
| |
| Rating Agency | Senior Secured Rating |
S&P (a) | A |
Moody’s (b) | A1 |
Fitch (c) | A |
__________
| |
| (a) | On August 9, 2018,April 30, 2019, S&P upgraded toaffirmed A rating. |
| |
| (b) | On December 12, 2018,20, 2019, Moody’s affirmed A1 rating. |
| |
| (c) | On October 11, 2018,August 29, 2019, Fitch affirmed A rating. |
We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings or other trigger events.ratings.
CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS
Contractual Obligations
In addition to our capital expenditure programs, we have contractual obligations and other commitments that will need to be funded in the future. The following information summarizes our cash obligations and commercial commitments at December 31, 20182019. Actual future obligations may differ materially from these estimated amounts (in thousands):
|
| | | | | | | | | | | | | | | |
| | 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| Contractual Obligations | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total |
Long-term debt(a) | $ | 5,743 |
| $ | 8,435 |
| $ | — |
| $ | 525,000 |
| $ | 2,855 |
| $ | 2,635,000 |
| $ | 3,177,033 |
|
Interest payments (a) | 131,859 |
| 131,842 |
| 131,756 |
| 131,756 |
| 109,390 |
| 1,273,648 |
| 1,910,251 |
|
Unconditional purchase obligations(b) | 181,773 |
| 159,827 |
| 134,018 |
| 105,583 |
| 54,098 |
| 126,147 |
| 761,446 |
|
Lease obligations(c) | 1,144 |
| 991 |
| 869 |
| 844 |
| 724 |
| 2,009 |
| 6,581 |
|
AROs (d) | 330 |
| 231 |
| 144 |
| 33 |
| 9,362 |
| 54,105 |
| 64,205 |
|
Employee benefit plans(e) | 18,921 |
| 19,678 |
| 19,736 |
| 19,944 |
| 19,896 |
| 35,580 |
| 133,755 |
|
| CP Program | 349,500 |
| — |
| — |
| — |
| — |
| — |
| 349,500 |
|
Total contractual cash obligations(f) | $ | 689,270 |
| $ | 321,004 |
| $ | 286,523 |
| $ | 783,160 |
| $ | 196,325 |
| $ | 4,126,489 |
| $ | 6,402,771 |
|
__________
| |
| (a) | Long-term debt amounts do not include deferred financing costs or 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, 20182019.
|
| |
(c)(b) | 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 20182019 and price assumptions using existing prices at December 31, 20182019. Our transmission obligations are based on filed tariffs as of December 31, 20182019. |
| |
| (c) | Includes leases associated with several office and operating facilities, communication tower sites, equipment and materials storage. |
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| (d) | Includes operating leasesRepresents estimated payments for AROs associated with several office buildings, warehouseslong-lived assets primarily related to retirement and call centers, equipmentreclamation of natural gas pipelines, mining sites, wind farms and vehicles. |
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(e) | Includes estimated asset retirement obligations associated with our Electric Utilities, Gas Utilitiesan evaporation pond. See Notes 1 and Mining segments as discussed in Note 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.10-K for additional information. |
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(f)(e) | Represents both estimated employer contributions to the Defined Benefit Pension Plan, and payments to employees for the Non-Pension Defined Benefit Postretirement Healthcare PlansPlan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2028.2029 as discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
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(g)(f) | 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, 20182019. 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.table; (3) our $4.2 million liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions as discussed in Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. |
Our Gas Utility segment hasUtilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. In addition, a portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure, are carried out for 60 days. As of December 31, 2018,2019, we are committed to purchase 10.2 million MMBtu, 3.7 million MMBtu, 3.7 million MMBtu, 1.8 million MMBtu and 0.01.8 million MMBtu in each of the years from 20192020 to 2023,2022, respectively.
Off-Balance Sheet Commitments
Guarantees
We have entered into various off-balance sheet commitments in the form of guarantees and letters of credit.
Guarantees
We provide various guarantees supporting certain of our subsidiaries under specified agreements or transactions. At December 31, 2018, we had outstanding guarantees as indicated in the table below. For more information on these guarantees, see Note 20 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
We had the following guarantees in place (in thousands):
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| 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 |
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(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. |
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(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. |
Letters of Credit
Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. We had $22 million inFor more information on these letters of credit, see Note 7 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Critical Accounting Policies Involving Significant Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments, or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Regulation
Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.
Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our Revolving Credit Facility at regulatory assets are probable of recovery in current rates or in future rate proceedings.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state public utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.
As of December 31, 2019 and 2018,. we had total regulatory assets of $271 million and $284 million, respectively, and total regulatory liabilities of $537 million and $541 million, respectively. See Note 13 of the Notes to the Consolidated Financial Statements for further information.
Goodwill
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.
Accounting standards for testing goodwill for impairment require a two-step process be performed to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. The first step of this test, used to identify potential impairment, compares the estimated fair value of a reporting unit with its carrying amount, including goodwill. If the carrying amount exceeds fair value under the first step, then the second step of the impairment test is performed to measure the amount of any impairment loss.
Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our 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. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed in the fourth quarter of 2019. Although 1% to 2% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews, as well as other improved efficiency and cost reduction initiatives. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.
The estimates and assumptions used in the impairment assessments are based on available market information and we believe they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. For the years ended December 31, 2019, 2018, and 2017, there were no impairment losses recorded. At December 31, 2019, the fair value substantially exceeded the carrying value at all reporting units.
As described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have prospectively adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, on January 1, 2020.
Pension and Other Postretirement Benefits
As described in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A trust for the funded portion of the post-retirement healthcare plan has also been established.
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.
The 2020 pension benefit cost for our non-contributory funded pension plan is expected to be $10.2 million compared to $2.1 million in 2019. The increase in pension benefit cost is driven primarily by a decrease in the discount rate and lower expected return on assets.
The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:
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| | December 31, |
| Assumptions | Percentage Change | 2019 Increase/(Decrease) PBO/APBO (a) | | 2020 Increase/(Decrease) Expense - Pretax |
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| Pension | | | | |
Discount rate (b) | +/- 0.5 | (28,998)/31,912 | | (3,965)/4,311 |
| Expected return on assets | +/- 0.5 | N/A | | (2,036)/2,036 |
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| OPEB | | | | |
Discount rate (b) | +/- 0.5 | (2,836)/3,095 | | 90/116 |
| Expected return on assets | +/- 0.5 | N/A | | (39)/39 |
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| (a) | Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans. |
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| (b) | Impact on service cost, interest cost and amortization of gains or losses. |
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.
The Company uses 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.
As of December 31, 2019, we have a regulatory liability associated with TCJA related items of $285 million, completing our accounting for the revaluation of deferred taxes pursuant to the TCJA. A significant portion 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, 2019, the Company has amortized $6.5 million of regulatory liability associated with TCJA related items. The portion that was eligible for amortization under the average rate assumption method in 2019, 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.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.
See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Market Risk Disclosures
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 adopteddisclosures are detailed in Note 9 of the Black Hills Corporation Risk Policies and Procedures.
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:
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.10-K, with additional information provided in the following paragraphs.
Our exposure to thesethe market risks detailed in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K is also affected by other factors including the size, duration and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates and the liquidity of the related interest rate and commodity markets.
The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee and reviewed by the Audit Committee of our Board of Directors.Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets on a regular basisat least quarterly and as necessary, appropriate or desirable, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.
Electric and Gas Utilities
We produce, purchase and distribute power in four states, and purchase and distribute natural gas in six states. Our utilities have ECA or GCAvarious provisions that allow them to pass the prudently-incurred cost of gasenergy through to the customer. To the extent that gasenergy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to “true-up” billed amounts to match the actual natural gasenergy cost we incurred. In Colorado, Montana, South Dakota and Wyoming, we have a mechanism forECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our regulated electric utilitiestariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that serves a purpose similar to the GCAs foradjust natural gas rates when our regulatednatural gas utilities. To the extent that our fuel and purchased power costs are higher or lower than the energy cost built intoincluded in our tariffs, the difference (or a portion thereof) is passed through to the customer.tariffs. These adjustments are subject to periodic prudence reviews by the state utility commissions. See additional information in Note 9 of ourthe Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
The fair value of our Electric and Gas Utilities derivative contracts at December 31 is summarized below (in thousands):
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| | 2018 | | 2017 |
| Net derivative (liabilities) assets | $ | (2,214 | ) | | $ | (6,644 | ) |
| Cash collateral | 7,266 |
| | 8,256 |
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| | $ | 5,052 |
| | $ | 1,612 |
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Wholesale Power
A potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. These potential short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.
Financing Activities
Historically,Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and anticipated debt refinancings. At December 31, 20182019, we had no interest rate swaps in place. As discussed in Item 7 - Liquidity and Capital Resources, 90% of our variable interest rate exposure has been mitigated through issuing fixed rate debt.
Further details of past swap agreements are set forth in Note 9 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
The table below presents principal amounts and related weighted average interest rates by year of maturity for our long-term debt obligations, including current maturities (dollars in thousands):
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| | 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 |
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| Average interest rate | 2.32 | % | 5.78 | % | 2.32 | % | — | % | 4.25 | % | 3.53 | % | 4.5 | % |
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| Variable rate | $ | — |
| $ | 300,000 |
| $ | 7,000 |
| $ | — |
| $ | — |
| $ | 12,855 |
| $ | 319,855 |
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Average interest rate (b) | — | % | 3.16 | % | 1.73 | % | — | % | — | % | 1.77 | % | 3.07 | % |
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| Total long-term debt | $ | 5,743 |
| $ | 505,743 |
| $ | 8,435 |
| $ | — |
| $ | 525,000 |
| $ | 1,937,855 |
| $ | 2,982,776 |
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Average interest rate (b) | 2.32 | % | 4.22 | % | 1.83 | % | — | % | 4.25 | % | 3.52 | % | 4.34 | % |
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(a) | Excludes unamortized premium or discount. |
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(b) | Interest rates as of December 31, 2018. |
Credit Risk
CreditOur credit risk isdisclosures are detailed in Note 9 of the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, with additional information provided below.
We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. In addition, our Executive Risk Committee, which includes senior executives, meets on a regular basis to review our credit activities and to monitor compliance with the adopted policies.
We seek to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements and securing our 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 our review of their current credit information. We maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and provisions established, we cannot provide assurance that we will continue to experience the same credit loss rates that we have in the past, or that an investment grade counterparty will not default sometime in the future.
Our credit exposure at December 31, 2018 was concentrated primarily among retail utility customers, investment grade companies, municipal cooperatives and federal agencies.
New Accounting Pronouncements
See Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 20182019 or pending adoption.
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| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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Management’s Report on Internal Control over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed 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.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 20182019, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 20182019.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of December 31, 2018.2019. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.
Black Hills Corporation
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the "Company"“Company”) as of December 31, 20182019 and 2017,2018, the related consolidated statements of income, comprehensive income, equity,cash flows, and cash flows,equity, for each of the three years in the period ended December 31, 2018,2019, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20182019 and 2017,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2019, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company'sCompany’s internal control over financial reporting as of December 31, 2018,2019, based on criteria established in Internal Control - IntegratedControl--Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 19, 2019,14, 2020, expressed an unqualified opinion on the Company'sCompany’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company'sCompany’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting--Impact of Rate Regulation on the Financial Statements--Refer to Note 1 and Note 13 to the financial statements
Critical Audit Matter Description
The Company is subject to cost-of-service regulation and earnings oversight by federal and state utility commissions (collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense).
Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to have been prudently incurred or that the rate regulation process in which rates are determined will always result in rates that produce a full recovery of costs and the return on invested capital.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers. Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
We read relevant regulatory orders issued by the Commissions, procedural memorandums, filings made by the Company, and other publicly available information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions.
We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 14, 2020
February 19, 2019
We have served as the Company’s auditor since 2002.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2018,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statementsand financial statement schedule of the Company as of and for the year ended December 31, 2018, of the Company,2019, and our report dated February 19, 201914, 2020 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 14, 2020
February 19, 2019
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
| | | Year ended | December 31, 2018 | December 31, 2017 | December 31, 2016 | December 31, 2019 | December 31, 2018 | December 31, 2017 |
| | (in thousands, except per share amounts) | (in thousands, except per share amounts) |
| | | |
| Revenue | $ | 1,754,268 |
| $ | 1,680,266 |
| $ | 1,538,916 |
| $ | 1,734,900 |
| $ | 1,754,268 |
| $ | 1,680,266 |
|
| | | |
| Operating expenses: | | |
| Fuel, purchased power and cost of natural gas sold | 625,610 |
| 563,288 |
| 499,132 |
| 570,829 |
| 625,610 |
| 563,288 |
|
| Operations and maintenance | 481,706 |
| 454,605 |
| 426,603 |
| 495,994 |
| 481,706 |
| 454,605 |
|
| Depreciation, depletion and amortization | 196,328 |
| 188,246 |
| 175,533 |
| 209,120 |
| 196,328 |
| 188,246 |
|
| Taxes - property and production | 51,746 |
| 51,578 |
| 46,160 |
| 52,915 |
| 51,746 |
| 51,578 |
|
| Other operating expenses | 1,841 |
| 5,813 |
| 55,307 |
| — |
| 1,841 |
| 5,813 |
|
| Total operating expenses | 1,357,231 |
| 1,263,530 |
| 1,202,735 |
| 1,328,858 |
| 1,357,231 |
| 1,263,530 |
|
| | | |
| Operating income | 397,037 |
| 416,736 |
| 336,181 |
| 406,042 |
| 397,037 |
| 416,736 |
|
| | | |
| 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 | ) | (145,847 | ) | (143,720 | ) | (140,533 | ) |
| Allowance for funds used during construction - borrowed | 2,104 |
| 2,415 |
| 2,981 |
| 6,556 |
| 2,104 |
| 2,415 |
|
| Interest income | 1,641 |
| 1,016 |
| 1,429 |
| 1,632 |
| 1,641 |
| 1,016 |
|
| Allowance for funds used during construction - equity | 619 |
| 2,321 |
| 3,270 |
| 472 |
| 619 |
| 2,321 |
|
| Impairment of investment | | (19,741 | ) | — |
| — |
|
| Other income (expense), net | (1,799 | ) | (213 | ) | 1,124 |
| (6,212 | ) | (1,799 | ) | (213 | ) |
| Total other income (expense) | (141,155 | ) | (134,994 | ) | (130,287 | ) | (163,140 | ) | (141,155 | ) | (134,994 | ) |
| Income before income taxes | 255,882 |
| 281,742 |
| 205,894 |
| 242,902 |
| 255,882 |
| 281,742 |
|
| Income tax benefit (expense) | 23,667 |
| (73,367 | ) | (59,101 | ) | (29,580 | ) | 23,667 |
| (73,367 | ) |
| Income from continuing operations | 279,549 |
| 208,375 |
| 146,793 |
| 213,322 |
| 279,549 |
| 208,375 |
|
| Net (loss) from discontinued operations | (6,887 | ) | (17,099 | ) | (64,162 | ) | — |
| (6,887 | ) | (17,099 | ) |
| Net income | 272,662 |
| 191,276 |
| 82,631 |
| 213,322 |
| 272,662 |
| 191,276 |
|
| Net income attributable to noncontrolling interest | (14,220 | ) | (14,242 | ) | (9,661 | ) | (14,012 | ) | (14,220 | ) | (14,242 | ) |
| Net income available for common stock | $ | 258,442 |
| $ | 177,034 |
| $ | 72,970 |
| $ | 199,310 |
| $ | 258,442 |
| $ | 177,034 |
|
| | | |
| Amounts attributable to common shareholders: | | |
| Net income from continuing operations | $ | 265,329 |
| $ | 194,133 |
| $ | 137,132 |
| $ | 199,310 |
| $ | 265,329 |
| $ | 194,133 |
|
| Net (loss) from discontinued operations | (6,887 | ) | (17,099 | ) | (64,162 | ) | — |
| (6,887 | ) | (17,099 | ) |
| Net income (loss) available for common stock | $ | 258,442 |
| $ | 177,034 |
| $ | 72,970 |
| |
| Net income available for common stock | | $ | 199,310 |
| $ | 258,442 |
| $ | 177,034 |
|
| | | |
| Earnings (loss) per share of common stock, Basic - | | |
| Earnings from continuing operations | $ | 4.88 |
| $ | 3.65 |
| $ | 2.64 |
| $ | 3.29 |
| $ | 4.88 |
| $ | 3.65 |
|
| (Loss) from discontinued operations | (0.13 | ) | (0.32 | ) | (1.23 | ) | — |
| (0.13 | ) | (0.32 | ) |
| Total earnings per share of common stock, Basic | $ | 4.75 |
| $ | 3.33 |
| $ | 1.41 |
| $ | 3.29 |
| $ | 4.75 |
| $ | 3.33 |
|
| | | |
| Earnings (loss) per share of common stock, Diluted - | | |
| Earnings from continuing operations | $ | 4.78 |
| $ | 3.52 |
| $ | 2.57 |
| $ | 3.28 |
| $ | 4.78 |
| $ | 3.52 |
|
| (Loss) from discontinued operations | (0.12 | ) | (0.31 | ) | (1.20 | ) | — |
| (0.12 | ) | (0.31 | ) |
| Total earnings per share of common stock, Diluted | $ | 4.66 |
| $ | 3.21 |
| $ | 1.37 |
| $ | 3.28 |
| $ | 4.66 |
| $ | 3.21 |
|
| | | |
| Weighted average common shares outstanding: | | |
| Basic | 54,420 |
| 53,221 |
| 51,922 |
| 60,662 |
| 54,420 |
| 53,221 |
|
| Diluted | 55,486 |
| 55,120 |
| 53,271 |
| 60,798 |
| 55,486 |
| 55,120 |
|
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| | | Year ended | December 31, 2018 | December 31, 2017 | December 31, 2016 | December 31, 2019 | December 31, 2018 | December 31, 2017 |
| | (in thousands) | (in thousands) |
| Net income | $ | 272,662 |
| $ | 191,276 |
| $ | 82,631 |
| $ | 213,322 |
| $ | 272,662 |
| $ | 191,276 |
|
| | | |
| 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 | ) | |
| Benefit plan liability adjustments - net gain (loss) (net of tax of $1,886, $(660) and $1,030, respectively) | | (6,253 | ) | 2,155 |
| (1,890 | ) |
| Benefit plan liability adjustments - prior service costs (net of tax of $2, $0 and $0, respectively) | | (8 | ) | — |
| — |
|
| Reclassification adjustment of benefit plan liability - net loss (net of tax of $434, $(586) and $(585), respectively) | | 1,179 |
| 1,901 |
| 1,072 |
|
| Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $19, $43 and $69, respectively) | | (58 | ) | (135 | ) | (128 | ) |
| 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 | ) | |
| Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(666), $(599) and$(1,029) , respectively) | | 2,185 |
| 2,252 |
| 1,912 |
|
| Net unrealized gains (losses) on commodity derivatives (net of tax of $126, $(228) and $(135), respectively) | | (422 | ) | 755 |
| 231 |
|
| Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $55, $(31) and $154, respectively) | | (362 | ) | 99 |
| (516 | ) |
| Other comprehensive income (loss), net of tax | 7,027 |
| 681 |
| (25,828 | ) | (3,739 | ) | 7,027 |
| 681 |
|
| | | |
| Comprehensive income | 279,689 |
| 191,957 |
| 56,803 |
| 209,583 |
| 279,689 |
| 191,957 |
|
| Less: comprehensive income attributable to non-controlling interest | (14,220 | ) | (14,242 | ) | (9,661 | ) | (14,012 | ) | (14,220 | ) | (14,242 | ) |
| Comprehensive income available for common stock | $ | 265,469 |
| $ | 177,715 |
| $ | 47,142 |
| $ | 195,571 |
| $ | 265,469 |
| $ | 177,715 |
|
See Note 16for additional disclosures related to Comprehensive Income.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
| | | | As of | As of |
| | December 31, 2018 | December 31, 2017 | December 31, 2019 | December 31, 2018 |
| | (in thousands) | (in thousands) |
| ASSETS | | |
| Current assets: | | |
| Cash and cash equivalents | $ | 20,776 |
| $ | 15,420 |
| $ | 9,777 |
| $ | 20,776 |
|
| Restricted cash and equivalents | 3,369 |
| 2,820 |
| 3,881 |
| 3,369 |
|
| Accounts receivable, net | 269,153 |
| 248,330 |
| 255,805 |
| 269,153 |
|
| Materials, supplies and fuel | 117,299 |
| 113,283 |
| 117,172 |
| 117,299 |
|
| Derivative assets, current | 1,500 |
| 304 |
| 342 |
| 1,500 |
|
| Income tax receivable, net | 12,978 |
| — |
| 16,446 |
| 12,978 |
|
| Regulatory assets, current | 48,776 |
| 81,016 |
| 43,282 |
| 48,776 |
|
| Other current assets | 29,982 |
| 25,367 |
| 26,479 |
| 29,982 |
|
| Current assets held for sale | — |
| 84,242 |
| |
| Total current assets | 503,833 |
| 570,782 |
| 473,184 |
| 503,833 |
|
| | | |
| Investments | 41,013 |
| 13,090 |
| 21,929 |
| 41,013 |
|
| | | | | |
| Property, plant and equipment | 6,000,015 |
| 5,567,518 |
| 6,784,679 |
| 6,000,015 |
|
| Less accumulated depreciation and depletion | (1,145,136 | ) | (1,026,088 | ) | (1,281,493 | ) | (1,145,136 | ) |
| Total property, plant and equipment, net | 4,854,879 |
| 4,541,430 |
| 5,503,186 |
| 4,854,879 |
|
| | | |
| Other assets: | | |
| Goodwill | 1,299,454 |
| 1,299,454 |
| 1,299,454 |
| 1,299,454 |
|
| Intangible assets, net | 14,337 |
| 7,559 |
| 13,266 |
| 14,337 |
|
| Regulatory assets, non-current | 235,459 |
| 216,438 |
| 228,062 |
| 235,459 |
|
| Other assets, non-current | 14,352 |
| 10,149 |
| 19,376 |
| 14,352 |
|
| Total other assets, non-current | 1,563,602 |
| 1,533,600 |
| 1,560,158 |
| 1,563,602 |
|
| TOTAL ASSETS | $ | 6,963,327 |
| $ | 6,658,902 |
| $ | 7,558,457 |
| $ | 6,963,327 |
|
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)
| | | | As of | | | | | |
| | December 31, 2018 | December 31, 2017 | As of |
| | (in thousands, except share amounts) | December 31, 2019 | December 31, 2018 |
| | | (in thousands, except share amounts) |
| LIABILITIES AND EQUITY | | |
| Current liabilities: | | |
| Accounts payable | $ | 210,609 |
| $ | 160,887 |
| $ | 193,523 |
| $ | 210,609 |
|
| Accrued liabilities | 215,501 |
| 219,462 |
| 226,767 |
| 215,501 |
|
| Derivative liabilities, current | 947 |
| 2,081 |
| 2,254 |
| 947 |
|
| Accrued income tax, net | — |
| 1,022 |
| |
| Regulatory liabilities, current | 29,810 |
| 6,832 |
| 33,507 |
| 29,810 |
|
| Notes payable | 185,620 |
| 211,300 |
| 349,500 |
| 185,620 |
|
| Current maturities of long-term debt | 5,743 |
| 5,743 |
| 5,743 |
| 5,743 |
|
| Current liabilities held for sale | — |
| 41,774 |
| |
| Total current liabilities | 648,230 |
| 649,101 |
| 811,294 |
| 648,230 |
|
| | | |
| Long-term debt, net of current maturities | 2,950,835 |
| 3,109,400 |
| 3,140,096 |
| 2,950,835 |
|
| | | |
| Deferred credits and other liabilities: | | |
| Deferred income tax liabilities, net | 311,331 |
| 336,520 |
| 360,719 |
| 311,331 |
|
| Regulatory liabilities, non-current | 510,984 |
| 478,294 |
| 503,145 |
| 510,984 |
|
| Benefit plan liabilities | 145,147 |
| 159,646 |
| 154,472 |
| 145,147 |
|
| Other deferred credits and other liabilities | 109,377 |
| 105,735 |
| 124,662 |
| 109,377 |
|
| Total deferred credits and other liabilities | 1,076,839 |
| 1,080,195 |
| 1,142,998 |
| 1,076,839 |
|
| | | |
| 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 |
| |
| Common stock $1 par value; 100,000,000 shares authorized; issued: 61,480,658 and 60,048,567, respectively | | 61,481 |
| 60,049 |
|
| Additional paid-in capital | 1,450,569 |
| 1,150,285 |
| 1,552,788 |
| 1,450,569 |
|
| Retained earnings | 700,396 |
| 548,617 |
| 778,776 |
| 700,396 |
|
| Treasury stock at cost - 44,253 and 39,064, respectively | (2,510 | ) | (2,306 | ) | |
| Treasury stock at cost - 3,956 and 44,253, respectively | | (267 | ) | (2,510 | ) |
| Accumulated other comprehensive income (loss) | (26,916 | ) | (41,202 | ) | (30,655 | ) | (26,916 | ) |
| Total stockholders’ equity | 2,181,588 |
| 1,708,974 |
| 2,362,123 |
| 2,181,588 |
|
| Noncontrolling interest | 105,835 |
| 111,232 |
| 101,946 |
| 105,835 |
|
| Total equity | 2,287,423 |
| 1,820,206 |
| 2,464,069 |
| 2,287,423 |
|
| | | |
| TOTAL LIABILITIES AND TOTAL EQUITY | $ | 6,963,327 |
| $ | 6,658,902 |
| $ | 7,558,457 |
| $ | 6,963,327 |
|
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| | | | | | | | | |
| Year ended | December 31, 2019 | December 31, 2018 | December 31, 2017 |
| | (in thousands) |
| Operating activities: | | | |
| Net income | $ | 213,322 |
| $ | 272,662 |
| $ | 191,276 |
|
| Loss from discontinued operations, net of tax | — |
| 6,887 |
| 17,099 |
|
| Income from continuing operations | 213,322 |
| 279,549 |
| 208,375 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | |
| Depreciation, depletion and amortization | 209,120 |
| 196,328 |
| 188,246 |
|
| Deferred financing cost amortization | 7,838 |
| 7,845 |
| 8,261 |
|
| Impairment of investment | 19,741 |
| — |
| — |
|
| Stock compensation | 12,095 |
| 12,390 |
| 7,626 |
|
| Deferred income taxes | 38,020 |
| (24,239 | ) | 80,992 |
|
| Employee benefit plans | 12,406 |
| 14,068 |
| 10,141 |
|
| Other adjustments, net | 16,485 |
| 5,836 |
| (4,773 | ) |
| Change in certain operating assets and liabilities: | | | |
| Materials, supplies and fuel | 2,052 |
| (2,919 | ) | (10,089 | ) |
| Accounts receivable and other current assets | 7,578 |
| (45,966 | ) | 4,534 |
|
| Accounts payable and other current liabilities | (34,906 | ) | 5,305 |
| (28,222 | ) |
| Regulatory assets - current | 23,619 |
| 33,608 |
| (15,407 | ) |
| Regulatory liabilities - current | (15,158 | ) | 18,533 |
| (4,536 | ) |
| Contributions to defined benefit pension plans | (12,700 | ) | (12,700 | ) | (27,700 | ) |
| Other operating activities, net | 6,001 |
| 6,689 |
| (8,418 | ) |
| Net cash provided by operating activities of continuing operations | 505,513 |
| 494,327 |
| 409,030 |
|
| Net cash provided by (used in) operating activities of discontinued operations | — |
| (5,516 | ) | 19,231 |
|
| Net cash provided by operating activities | 505,513 |
| 488,811 |
| 428,261 |
|
| | | | |
| Investing activities: | | | |
| Property, plant and equipment additions | (818,376 | ) | (457,524 | ) | (326,010 | ) |
| Purchase of investment | — |
| (24,429 | ) | — |
|
| Other investing activities | 2,166 |
| (4,281 | ) | 1,011 |
|
| Net cash (used in) investing activities of continuing operations | (816,210 | ) | (486,234 | ) | (324,999 | ) |
| Net cash provided by investing activities of discontinued operations | — |
| 20,385 |
| 7,881 |
|
| Net cash (used in) investing activities | (816,210 | ) | (465,849 | ) | (317,118 | ) |
| | | | |
| Financing activities: | | | |
| Dividends paid on common stock | (124,647 | ) | (106,591 | ) | (96,744 | ) |
| Common stock issued | 101,358 |
| 300,834 |
| 4,408 |
|
| Net (payments) borrowings of short-term debt | 163,880 |
| (25,680 | ) | 114,700 |
|
| Long-term debt - issuance | 1,100,000 |
| 700,000 |
| — |
|
| Long-term debt - repayments | (905,743 | ) | (854,743 | ) | (105,743 | ) |
| Distributions to noncontrolling interests | (17,901 | ) | (19,617 | ) | (18,397 | ) |
| Other financing activities | (16,737 | ) | (11,260 | ) | (6,919 | ) |
| Net cash provided by (used in) financing activities | 300,210 |
| (17,057 | ) | (108,695 | ) |
| | | | |
| Net change in cash, restricted cash and cash equivalents | (10,487 | ) | 5,905 |
| 2,448 |
|
| | | | |
| Cash, restricted cash and cash equivalents beginning of year | 24,145 |
| 18,240 |
| 15,792 |
|
| Cash, restricted cash and cash equivalents end of year | $ | 13,658 |
| $ | 24,145 |
| $ | 18,240 |
|
|
| | | | | | | | | |
| 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 |
|
See Note 17 for supplemental disclosure of cash flow information.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
| | | | Common Stock | Treasury Stock | | Common Stock | Treasury Stock | |
| (in thousands except share amounts) | Shares | Value | Shares | Value | Additional Paid in Capital | Retained Earnings | AOCI | Non controlling Interest | Total | 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 |
| 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 |
| — |
| — |
| — |
| — |
| — |
| 177,034 |
| — |
| 14,242 |
| 191,276 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 681 |
| — |
| 681 |
| — |
| — |
| — |
| — |
| — |
| — |
| 681 |
| — |
| 681 |
|
| Reclassification of certain tax effects from AOCI | — |
| — |
| — |
| — |
| — |
| 7,000 |
| (7,000 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| 7,000 |
| (7,000 | ) | — |
| — |
|
| Dividends on common stock | — |
| — |
| — |
| — |
| — |
| (96,744 | ) | — |
| — |
| (96,744 | ) | — |
| — |
| — |
| — |
| — |
| (96,744 | ) | — |
| — |
| (96,744 | ) |
| Share-based compensation | 134,266 |
| 134 |
| 23,806 |
| (1,515 | ) | 8,948 |
| — |
| — |
| — |
| 7,567 |
| 134,266 |
| 134 |
| 23,806 |
| (1,515 | ) | 8,948 |
| — |
| — |
| — |
| 7,567 |
|
| Tax effect of share-based compensation | — |
| — |
| — |
| — |
| 533 |
| 3,184 |
| — |
| — |
| 3,717 |
| — |
| — |
| — |
| — |
| 533 |
| 3,184 |
| — |
| — |
| 3,717 |
|
| Issuance costs | — |
| — |
| — |
| — |
| (189 | ) | — |
| — |
| — |
| (189 | ) | — |
| — |
| — |
| — |
| (189 | ) | — |
| — |
| — |
| (189 | ) |
| Dividend reinvestment and stock purchase plan | 48,253 |
| 49 |
| — |
| — |
| 3,107 |
| — |
| — |
| — |
| 3,156 |
| 48,253 |
| 49 |
| — |
| — |
| 3,107 |
| — |
| — |
| — |
| 3,156 |
|
| Redemption of and distributions to noncontrolling interest | — |
| — |
| — |
| — |
| (1,096 | ) | 209 |
| — |
| (18,505 | ) | (19,392 | ) | |
| 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 |
| 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 |
| — |
| — |
| — |
| — |
| — |
| 258,442 |
| — |
| 14,220 |
| 272,662 |
|
| Other comprehensive income (loss), net of tax | — |
| — |
| — |
| — |
| — |
| — |
| 7,027 |
| — |
| 7,027 |
| — |
| — |
| — |
| — |
| — |
| — |
| 7,027 |
| — |
| 7,027 |
|
| Reclassification of certain tax effects from AOCI | — |
| — |
| — |
| — |
| — |
| — |
| 740 |
| — |
| 740 |
| — |
| — |
| — |
| — |
| — |
| — |
| 740 |
| — |
| 740 |
|
| Reclassification to regulatory asset | — |
| — |
| — |
| — |
| — |
| — |
| 6,519 |
| — |
| 6,519 |
| — |
| — |
| — |
| — |
| — |
| — |
| 6,519 |
| — |
| 6,519 |
|
| Dividends on common stock | — |
| — |
| — |
| — |
| — |
| (106,591 | ) | — |
| — |
| (106,591 | ) | — |
| — |
| — |
| — |
| — |
| (106,591 | ) | — |
| — |
| (106,591 | ) |
| Share-based compensation | 92,830 |
| 93 |
| 5,189 |
| (204 | ) | 7,301 |
| — |
| — |
| — |
| 7,190 |
| 92,830 |
| 93 |
| 5,189 |
| (204 | ) | 7,301 |
| — |
| — |
| — |
| 7,190 |
|
| Issuance of common stock | 6,371,690 |
| 6,372 |
| — |
| — |
| 292,628 |
| — |
| — |
| — |
| 299,000 |
| 6,371,690 |
| 6,372 |
| — |
| — |
| 292,628 |
| — |
| — |
| — |
| 299,000 |
|
| Issuance costs | — |
| — |
| — |
| — |
| (15 | ) | — |
| — |
| — |
| (15 | ) | — |
| — |
| — |
| — |
| (15 | ) | — |
| — |
| — |
| (15 | ) |
| Dividend reinvestment and stock purchase plan | 4,061 |
| 4 |
| — |
| — |
| 216 |
| — |
| — |
| — |
| 220 |
| 4,061 |
| 4 |
| — |
| — |
| 216 |
| — |
| — |
| — |
| 220 |
|
| Other stock transactions | — |
| — |
| — |
| — |
| 154 |
| (72 | ) | — |
| — |
| 82 |
| — |
| — |
| — |
| — |
| 154 |
| (72 | ) | — |
| — |
| 82 |
|
| Redemption of and 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 |
|
| Net income (loss) available for common stock | | — |
| — |
| — |
| — |
| — |
| 199,310 |
| — |
| 14,012 |
| 213,322 |
|
| Other comprehensive income (loss), net of tax | | — |
| — |
| — |
| — |
| — |
| — |
| (3,739 | ) | — |
| (3,739 | ) |
| Dividends on common stock | | — |
| — |
| — |
| — |
| — |
| (124,647 | ) | — |
| — |
| (124,647 | ) |
| Share-based compensation | | 103,759 |
| 104 |
| (40,297 | ) | 2,243 |
| 4,729 |
| — |
| — |
| — |
| 7,076 |
|
| Issuance of common stock | | 1,328,332 |
| 1,328 |
| — |
| — |
| 98,672 |
| — |
| — |
| — |
| 100,000 |
|
| Issuance costs | | — |
| — |
| — |
| — |
| (1,182 | ) | — |
| — |
| — |
| (1,182 | ) |
| Other | | — |
| — |
| — |
| — |
| — |
| 327 |
| — |
| — |
| 327 |
|
| Implementation of ASU 2016-02 Leases | | — |
| — |
| — |
| — |
| — |
| 3,390 |
| — |
| — |
| 3,390 |
|
| Distributions to noncontrolling interest | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (19,617 | ) | (19,617 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| (17,901 | ) | (17,901 | ) |
| 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 |
| |
| Balance at December 31, 2019 | | 61,480,658 |
| $ | 61,481 |
| 3,956 |
| $ | (267 | ) | $ | 1,552,788 |
| $ | 778,776 |
| $ | (30,655 | ) | $ | 101,946 |
| $ | 2,464,069 |
|
__________________
Dividends per share paid were $2.05, $1.93, and $1.81 and $1.68 for the years ended December 31, 20182019, 20172018 and 20162017, respectively.
BLACK HILLS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 20182019, 20172018 and 20162017
| |
(1) | 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 Colorado Electric, South Dakota Electric, Wyoming Electric and ColoradoWyoming 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.
AllMost 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 WyomingColorado, Iowa and Colorado.Wyoming. 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 beenwere classified as held for sale and the results of operations arewere shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which dodid not meet the criteria for income (loss) from discontinued operations.operations in 2018 or 2017. 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 21.21.
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 12.12.
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 MiningPower Generation and Power GenerationMining business segments consists of amounts due from sales of coal, electric energy and capacity.capacity and coal.
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):
| | | 2018 | Accounts Receivable, Trade | Unbilled Revenue | Less Allowance for Doubtful Accounts | Accounts Receivable, net | |
| 2019 | | Accounts Receivable, Trade | Unbilled Revenue | Less Allowance for Doubtful Accounts | Accounts Receivable, net |
| Electric Utilities | $ | 39,721 |
| $ | 35,125 |
| $ | (448 | ) | $ | 74,398 |
| $ | 41,428 |
| $ | 33,886 |
| $ | (592 | ) | $ | 74,722 |
|
| Gas Utilities | 96,123 |
| 90,521 |
| (2,592 | ) | 184,052 |
| 97,607 |
| 79,616 |
| (1,683 | ) | 175,540 |
|
| Power Generation | 1,876 |
| — |
| — |
| 1,876 |
| 2,164 |
| — |
| — |
| 2,164 |
|
| Mining | 3,988 |
| — |
| — |
| 3,988 |
| 2,277 |
| — |
| — |
| 2,277 |
|
| Corporate | 5,008 |
| — |
| (169 | ) | 4,839 |
| 1,271 |
| — |
| (169 | ) | 1,102 |
|
| Total | $ | 146,716 |
| $ | 125,646 |
| $ | (3,209 | ) | $ | 269,153 |
| $ | 144,747 |
| $ | 113,502 |
| $ | (2,444 | ) | $ | 255,805 |
|
|
| | | | | | | | | | | | |
| 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 |
|
Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
|
________________(a) Represents allowance |
| | | | | | | | | | | | | | | | | | | | |
| | | Balance at Beginning of Year | | Additions Charged to Costs and Expenses | | Recoveries and Other Additions | | Write-offs and Other Deductions | | Balance at End of Year |
| 2019 | | $ | 3,209 |
| | $ | 5,795 |
| | $ | 3,942 |
| | $ | (10,502 | ) | | $ | 2,444 |
|
| 2018 | | $ | 3,081 |
| | $ | 6,859 |
| | $ | 4,092 |
| | $ | (10,823 | ) | | $ | 3,209 |
|
| 2017 | | $ | 2,392 |
| | $ | 4,926 |
| | $ | 8,262 |
| | $ | (12,499 | ) | | $ | 3,081 |
|
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):
|
| | | | | | |
| | 2019 | 2018 |
| Materials and supplies | $ | 82,809 |
| $ | 75,081 |
|
| Fuel - Electric Utilities | 2,425 |
| 2,850 |
|
| Natural gas in storage | 31,938 |
| 39,368 |
|
| Total materials, supplies and fuel | $ | 117,172 |
| $ | 117,299 |
|
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
In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. 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.
During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10%. Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million, which was the difference between the carrying amount and the fair value of the investment.
The following table presents the carrying value of our investments (in thousands) as of December 31:
|
| | | | | | |
| | 2019 | 2018 |
| Investment in privately held oil and gas company | $ | 8,359 |
| $ | 28,100 |
|
| Cash surrender value of life insurance contracts | 13,056 |
| 12,812 |
|
| Other investments | 514 |
| 101 |
|
| Total investments | $ | 21,929 |
| $ | 41,013 |
|
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.
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 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 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 amounts have not changed since 2016. As of December 31, 2019, 2018 and 2017, Goodwill balances were as follows (in thousands):
|
| | | | | | | | | | | | |
| Electric Utilities | Gas Utilities | Power Generation | Total |
| Goodwill | $ | 248,479 |
| $ | 1,042,210 |
| $ | 8,765 |
| $ | 1,299,454 |
|
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):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Intangible assets, net, beginning balance | $ | 14,337 |
| $ | 7,559 |
| $ | 8,392 |
|
Additions (a) | — |
| 7,602 |
| — |
|
Amortization expense (b) | (1,071 | ) | (824 | ) | (833 | ) |
| Intangible assets, net, ending balance | $ | 13,266 |
| $ | 14,337 |
| $ | 7,559 |
|
_________________
| |
| (a) | The 2018 addition is related to the Busch Ranch 1 contract intangible asset. See Note 4 for further information. |
| |
| (b) | Amortization expense for existing intangible assets is expected to be $1.1 million for each year of the next five years. |
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):
|
| | | | | | |
| | 2019 | 2018 |
| Accrued employee compensation, benefits and withholdings | $ | 62,837 |
| $ | 63,742 |
|
| Accrued property taxes | 44,547 |
| 42,510 |
|
| Customer deposits and prepayments | 54,728 |
| 43,574 |
|
| Accrued interest | 31,868 |
| 31,759 |
|
| CIAC current portion | 1,952 |
| 1,485 |
|
| Other (none of which is individually significant) | 30,835 |
| 32,431 |
|
| Total accrued liabilities | $ | 226,767 |
| $ | 215,501 |
|
Asset Retirement Obligations
Accounting standards for AROs 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. 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. Additional information is included in Note 8.
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 when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Valuation Methodologies for Derivatives
The commodity contracts for our Electric and Gas Utilities are valued using the market approach and include Level 2 exchange-traded futures, options, basis swaps and over-the-counter swaps for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable instrument. For over-the-counter instruments, fair value was obtained by utilizing a nationally recognized service that obtains observable inputs to compute fair value, which we validate by comparing our valuation with the SourceGas acquisition.counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.
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 Utilities’ 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.
Revenue RecognitionWe 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.
Revenue
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 include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities.
Regulatory Accounting
Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred
Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.
As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million respectively, and total regulatory liabilities of $537 million and $541 million respectively. See Note 13 for further information.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state 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.
It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs 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 ITC 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.
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 or in Deferred income tax liabilities, net 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 per share is as follows for the years ended December 31 (in thousands):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| | | | |
| Net income available for common stock | $ | 199,310 |
| $ | 258,442 |
| $ | 177,034 |
|
| | | | |
| Weighted average shares - basic | 60,662 |
| 54,420 |
| 53,221 |
|
| Dilutive effect of: | | | |
| Equity Units | — |
| 898 |
| 1,783 |
|
| Equity compensation | 136 |
| 168 |
| 116 |
|
| Weighted average shares - diluted | 60,798 |
| 55,486 |
| 55,120 |
|
| | | | |
| Net income available for common stock, per share - Diluted | $ | 3.28 |
| $ | 4.66 |
| $ | 3.21 |
|
The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands):
|
| | | | | | |
| | 2019 | 2018 | 2017 |
| | | | |
| Equity compensation | 1 |
| 16 |
| 11 |
|
| Anti-dilutive shares excluded from computation of earnings per share | 1 |
| 16 |
| 11 |
|
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
Simplifying the Accounting for Income Taxes, ASU 2019-12
In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.
Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15
In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.
Simplifying the Test for Goodwill Impairment, ASU 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 reflectsexcess, limited to the considerationamount 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 adopted this standard prospectively on January 1, 2020. Adoption of this guidance is not expected to have any impact on our financial position, results of operations or cash flows.
Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19
In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted.
We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we expectrecorded an increase to receive in exchangeour allowance for goodsdoubtful accounts, primarily associated with the inclusion of expected losses on unbilled revenue. Adoption of this standard did not have a material impact on our financial position, results of operations or services, when controlcash flows.
Recently Adopted Accounting Standards
Leases, ASU 2016-02
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.
We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.
Adoption of the promised goodsnew standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings at January 1, 2019.
See Note 14 for additional details on leases.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 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. 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.
(2)REVENUE
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services is transferredthat are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers.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. Our primary types of revenue contracts are:
| |
| • | 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 tariff rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations 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 state or federal regulatory commissions 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, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. |
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.
| |
| • | 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 supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered. |
| |
| • | Other non-regulated services - Our Electric and Gas 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. |
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
Hills also sells excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered.
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.
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 yearyears ended December 31, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues.
|
| | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2019 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
| Customer types: | (in thousands) |
| Retail | $ | 605,756 |
| $ | 817,840 |
| $ | — |
| $ | 59,233 |
| $ | (32,053 | ) | $ | 1,450,776 |
|
| Transportation | — |
| 143,390 |
| — |
| — |
| (1,042 | ) | 142,348 |
|
| Wholesale | 20,884 |
| — |
| 99,157 |
| — |
| (91,577 | ) | 28,464 |
|
| Market - off-system sales | 23,817 |
| 691 |
| — |
| — |
| (7,736 | ) | 16,772 |
|
| Transmission/Other | 57,104 |
| 47,725 |
| — |
| — |
| (16,797 | ) | 88,032 |
|
| Revenue from contracts with customers | 707,561 |
| 1,009,646 |
| 99,157 |
| 59,233 |
| (149,205 | ) | 1,726,392 |
|
| Other revenues | 5,191 |
| 384 |
| 2,101 |
| 2,396 |
| (1,564 | ) | 8,508 |
|
| Total revenues | $ | 712,752 |
| $ | 1,010,030 |
| $ | 101,258 |
| $ | 61,629 |
| $ | (150,769 | ) | $ | 1,734,900 |
|
|
|
|
|
|
|
|
| Timing of revenue recognition: |
|
|
|
|
|
|
| Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 59,233 |
| $ | (32,053 | ) | $ | 27,180 |
|
| Services transferred over time | 707,561 |
| 1,009,646 |
| 99,157 |
| — |
| (117,152 | ) | 1,699,212 |
|
| Revenue from contracts with customers | $ | 707,561 |
| $ | 1,009,646 |
| $ | 99,157 |
| $ | 59,233 |
| $ | (149,205 | ) | $ | 1,726,392 |
|
| | | Year ended December 31, 2018 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total | Electric Utilities | Gas Utilities | Power Generation (a) | Mining | Inter-company Revenues (a) | Total |
| Customer types: | (in thousands) | (in thousands) |
| Retail | $ | 594,329 |
| $ | 833,379 |
| $ | — |
| $ | 65,803 |
| $ | (32,194 | ) | $ | 1,461,317 |
| $ | 594,329 |
| $ | 833,379 |
| $ | — |
| $ | 65,803 |
| $ | (32,194 | ) | $ | 1,461,317 |
|
| Transportation | — |
| 140,705 |
| — |
| — |
| (1,348 | ) | 139,357 |
| — |
| 140,705 |
| — |
| — |
| (1,348 | ) | 139,357 |
|
| Wholesale | 33,687 |
| — |
| 52,396 |
| — |
| (46,562 | ) | 39,521 |
| 33,687 |
| — |
| 90,791 |
| — |
| (84,957 | ) | 39,521 |
|
| Market - off-system sales | 24,799 |
| 866 |
| — |
| — |
| (8,102 | ) | 17,563 |
| 24,799 |
| 866 |
| — |
| — |
| (8,102 | ) | 17,563 |
|
| Transmission/Other | 56,209 |
| 49,402 |
| — |
| — |
| (14,827 | ) | 90,784 |
| 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 |
| 709,024 |
| 1,024,352 |
| 90,791 |
| 65,803 |
| (141,428 | ) | 1,748,542 |
|
| Other revenues | 2,427 |
| 955 |
| 36,556 |
| 2,230 |
| (36,442 | ) | 5,726 |
| 2,427 |
| 955 |
| 1,660 |
| 2,230 |
| (1,546 | ) | 5,726 |
|
| Total revenues | $ | 711,451 |
| $ | 1,025,307 |
| $ | 88,952 |
| $ | 68,033 |
| $ | (139,475 | ) | $ | 1,754,268 |
| $ | 711,451 |
| $ | 1,025,307 |
| $ | 92,451 |
| $ | 68,033 |
| $ | (142,974 | ) | $ | 1,754,268 |
|
| | | |
| Timing of revenue recognition: | | |
| Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 65,803 |
| $ | (32,194 | ) | $ | 33,609 |
| $ | — |
| $ | — |
| $ | — |
| $ | 65,803 |
| $ | (32,194 | ) | $ | 33,609 |
|
| Services transferred over time | 709,024 |
| 1,024,352 |
| 52,396 |
| — |
| (70,839 | ) | 1,714,933 |
| 709,024 |
| 1,024,352 |
| 90,791 |
| — |
| (109,234 | ) | 1,714,933 |
|
| Revenue from contracts with customers | $ | 709,024 |
| $ | 1,024,352 |
| $ | 52,396 |
| $ | 65,803 |
| $ | (103,033 | ) | $ | 1,748,542 |
| $ | 709,024 |
| $ | 1,024,352 |
| $ | 90,791 |
| $ | 65,803 |
| $ | (141,428 | ) | $ | 1,748,542 |
|
| |
| (a) | Due to the changes in our segment disclosures discussed in Note 5, Power Generation Wholesale revenue was revised for the year ended December 31, 2018, which resulted in an increase of $38 million. The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million. There was no impact to our consolidated Total 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 840,842, 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 agreementEffective January 1, 2019, we changed how we account for the PPA between Black Hills Colorado IPP and affiliate Colorado Electric. This agreement is accountedElectric at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 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.additional information.
Significant JudgmentsGoodwill and EstimatesIntangible Assets
TCJA Revenue Reserve
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.
The TCJA or “tax reform” signed into law on December 22, 2017, reducedOur goodwill impairment analysis includes an income approach and a market approach to estimate the federal corporate income taxfair 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, from 35% to 21% effectivetiming and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for tax years beginning after December 31, 2017. Black Hills has been collaborating with utility commissions incomparable companies.
We believe that the states in which it provides utility service to deliver to customersgoodwill reflects the benefits of a lower corporate federal income tax rate beginning in 2018 with the passageinherent value of the TCJA. Werelatively 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 amounts 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.not changed since 2016. As of December 31, 2019, 2018 $19and 2017, Goodwill balances were as follows (in thousands):
|
| | | | | | | | | | | | |
| Electric Utilities | Gas Utilities | Power Generation | Total |
| Goodwill | $ | 248,479 |
| $ | 1,042,210 |
| $ | 8,765 |
| $ | 1,299,454 |
|
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):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Intangible assets, net, beginning balance | $ | 14,337 |
| $ | 7,559 |
| $ | 8,392 |
|
Additions (a) | — |
| 7,602 |
| — |
|
Amortization expense (b) | (1,071 | ) | (824 | ) | (833 | ) |
| Intangible assets, net, ending balance | $ | 13,266 |
| $ | 14,337 |
| $ | 7,559 |
|
_________________
| |
| (a) | The 2018 addition is related to the Busch Ranch 1 contract intangible asset. See Note 4 for further information. |
| |
| (b) | Amortization expense for existing intangible assets is expected to be $1.1 million for each year of the next five years. |
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):
|
| | | | | | |
| | 2019 | 2018 |
| Accrued employee compensation, benefits and withholdings | $ | 62,837 |
| $ | 63,742 |
|
| Accrued property taxes | 44,547 |
| 42,510 |
|
| Customer deposits and prepayments | 54,728 |
| 43,574 |
|
| Accrued interest | 31,868 |
| 31,759 |
|
| CIAC current portion | 1,952 |
| 1,485 |
|
| Other (none of which is individually significant) | 30,835 |
| 32,431 |
|
| Total accrued liabilities | $ | 226,767 |
| $ | 215,501 |
|
Asset Retirement Obligations
Accounting standards for AROs 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. The accounting for the obligation for regulated operations has beenno 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. Additional information is included in Note 8.
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 when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Valuation Methodologies for Derivatives
The commodity contracts for our Electric and Gas Utilities are valued using the market approach and include Level 2 exchange-traded futures, options, basis swaps and over-the-counter swaps for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable instrument. For over-the-counter instruments, fair value was obtained by utilizing a nationally recognized service that obtains observable inputs to compute fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.
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 Utilities’ 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 include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities.
Regulatory Accounting
Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred
Management continually assesses the probability of future recoveries and approximately $18obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.
As of December 31, 2019 and 2018, we had total regulatory assets of $271 million remainsand $284 million respectively, and total regulatory liabilities of $537 million and $541 million respectively. See Note 13 for further information.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state 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 reserveaccounting 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.
It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a current regulatory liability.
Unbilled Revenue
Toreduction to income tax expense in the extent that deliveries have occurred butyear they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a bill has not been issued, our utilities accrue an estimatemethod results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the revenue sinceunderlying property that gave rise to the latest billing. This estimatecredit.
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.
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 calculated based upon several factors including billings through the last billing cycleclassified in a monthOther deferred credits and pricesother liabilities or in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable,Deferred income tax liabilities, net 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 per share is as follows for the years ended December 31 (in thousands):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| | | | |
| Net income available for common stock | $ | 199,310 |
| $ | 258,442 |
| $ | 177,034 |
|
| | | | |
| Weighted average shares - basic | 60,662 |
| 54,420 |
| 53,221 |
|
| Dilutive effect of: | | | |
| Equity Units | — |
| 898 |
| 1,783 |
|
| Equity compensation | 136 |
| 168 |
| 116 |
|
| Weighted average shares - diluted | 60,798 |
| 55,486 |
| 55,120 |
|
| | | | |
| Net income available for common stock, per share - Diluted | $ | 3.28 |
| $ | 4.66 |
| $ | 3.21 |
|
The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands):
|
| | | | | | |
| | 2019 | 2018 | 2017 |
| | | | |
| Equity compensation | 1 |
| 16 |
| 11 |
|
| Anti-dilutive shares excluded from computation of earnings per share | 1 |
| 16 |
| 11 |
|
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
Simplifying the Accounting for Income Taxes, ASU 2019-12
In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740, Income Taxes, and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.
Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, BalancesASU 2018-15
In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows.
Simplifying the Test for Goodwill Impairment, ASU 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 adopted this standard prospectively on January 1, 2020. Adoption of this guidance is not expected to have any impact on our financial position, results of operations or cash flows.
Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19
In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted.
We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for doubtful accounts, primarily associated with the inclusion of expected losses on unbilled revenue. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.
The natureRecently Adopted Accounting Standards
Leases, ASU 2016-02
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the recognition of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contractright-of-use assets orand lease liabilities exist. The unconditional right to consideration is represented byon the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.
We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.
Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and an accrued receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings at January 1, 2019.
See Note 14 for additional details on leases.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 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. We have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our Accounts Receivable further discussed above. We do not typically incur costs that would be capitalized to obtainfinancial position, results of operations or fulfill a contract.cash flows.
Practical Expedients
(2)REVENUE
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. Our primary types of revenue contracts are:
| |
| • | 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 tariff rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations 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 state or federal regulatory commissions 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, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. |
| |
| • | 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 supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered. |
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.
| |
| • | Other non-regulated services - Our Electric and Gas 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. |
Materials, Supplies and Fuel
The following amountstables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by major classification are included in Materials, suppliescustomer type and fuel ontiming of revenue recognition for each of the accompanying Consolidated Balance Sheets as ofreporting segments, for the years ended December 31, (in thousands):2019 and 2018. Sales tax and other similar taxes are excluded from revenues.
|
| | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2019 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
| Customer types: | (in thousands) |
| Retail | $ | 605,756 |
| $ | 817,840 |
| $ | — |
| $ | 59,233 |
| $ | (32,053 | ) | $ | 1,450,776 |
|
| Transportation | — |
| 143,390 |
| — |
| — |
| (1,042 | ) | 142,348 |
|
| Wholesale | 20,884 |
| — |
| 99,157 |
| — |
| (91,577 | ) | 28,464 |
|
| Market - off-system sales | 23,817 |
| 691 |
| — |
| — |
| (7,736 | ) | 16,772 |
|
| Transmission/Other | 57,104 |
| 47,725 |
| — |
| — |
| (16,797 | ) | 88,032 |
|
| Revenue from contracts with customers | 707,561 |
| 1,009,646 |
| 99,157 |
| 59,233 |
| (149,205 | ) | 1,726,392 |
|
| Other revenues | 5,191 |
| 384 |
| 2,101 |
| 2,396 |
| (1,564 | ) | 8,508 |
|
| Total revenues | $ | 712,752 |
| $ | 1,010,030 |
| $ | 101,258 |
| $ | 61,629 |
| $ | (150,769 | ) | $ | 1,734,900 |
|
|
|
|
|
|
|
|
| Timing of revenue recognition: |
|
|
|
|
|
|
| Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 59,233 |
| $ | (32,053 | ) | $ | 27,180 |
|
| Services transferred over time | 707,561 |
| 1,009,646 |
| 99,157 |
| — |
| (117,152 | ) | 1,699,212 |
|
| Revenue from contracts with customers | $ | 707,561 |
| $ | 1,009,646 |
| $ | 99,157 |
| $ | 59,233 |
| $ | (149,205 | ) | $ | 1,726,392 |
|
|
| | | | | | |
| | 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 |
|
|
| | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2018 | Electric Utilities | Gas Utilities | Power Generation (a) | Mining | Inter-company Revenues (a) | 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 |
| — |
| 90,791 |
| — |
| (84,957 | ) | 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 |
| 90,791 |
| 65,803 |
| (141,428 | ) | 1,748,542 |
|
| Other revenues | 2,427 |
| 955 |
| 1,660 |
| 2,230 |
| (1,546 | ) | 5,726 |
|
| Total revenues | $ | 711,451 |
| $ | 1,025,307 |
| $ | 92,451 |
| $ | 68,033 |
| $ | (142,974 | ) | $ | 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 |
| 90,791 |
| — |
| (109,234 | ) | 1,714,933 |
|
| Revenue from contracts with customers | $ | 709,024 |
| $ | 1,024,352 |
| $ | 90,791 |
| $ | 65,803 |
| $ | (141,428 | ) | $ | 1,748,542 |
|
| |
| (a) | Due to the changes in our segment disclosures discussed in Note 5, Power Generation Wholesale revenue was revised for the year ended December 31, 2018, which resulted in an increase of $38 million. The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million. There was no impact to our consolidated Total Revenues. |
Materials and supplies represent parts and supplies for allThe majority of our business segments. Fuel -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 842, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. Effective January 1, 2019, we changed how we account for the PPA between Black Hills Colorado IPP and Colorado 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 businesssegment level and the commodity price of natural gas.now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information.
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:
|
| | | | | | |
| | 2018 | 2017 |
| Cost method investment | $ | 28,201 |
| $ | — |
|
| Cash surrender value of life insurance contracts | 12,812 |
| 13,090 |
|
| Total investments | $ | 41,013 |
| $ | 13,090 |
|
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):
|
| | | | | | |
| | 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 |
|
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 amounts have not changed since 2016. As of December 31, 2019, 2018 and 2017, Goodwill balances were as follows (in thousands):
|
| | | | | | | | | | | | |
| Electric Utilities | Gas Utilities | Power Generation | Total |
| Goodwill | $ | 248,479 |
| $ | 1,042,210 |
| $ | 8,765 |
| $ | 1,299,454 |
|
|
| | | | | | | | | | | | |
| | 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 |
|
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):
| | | | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| Intangible assets, net, beginning balance | $ | 7,559 |
| $ | 8,392 |
| $ | 3,380 |
| $ | 14,337 |
| $ | 7,559 |
| $ | 8,392 |
|
Additions (a) | 7,602 |
| — |
| 5,522 |
| — |
| 7,602 |
| — |
|
Amortization expense (b) | (824 | ) | (833 | ) | (510 | ) | (1,071 | ) | (824 | ) | (833 | ) |
| Intangible assets, net, ending balance | $ | 14,337 |
| $ | 7,559 |
| $ | 8,392 |
| $ | 13,266 |
| $ | 14,337 |
| $ | 7,559 |
|
_________________
| |
| (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$1.1 million for each year of the next five years. |
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):
|
| | | | | | |
| | 2019 | 2018 |
| Accrued employee compensation, benefits and withholdings | $ | 62,837 |
| $ | 63,742 |
|
| Accrued property taxes | 44,547 |
| 42,510 |
|
| Customer deposits and prepayments | 54,728 |
| 43,574 |
|
| Accrued interest | 31,868 |
| 31,759 |
|
| CIAC current portion | 1,952 |
| 1,485 |
|
| Other (none of which is individually significant) | 30,835 |
| 32,431 |
|
| Total accrued liabilities | $ | 226,767 |
| $ | 215,501 |
|
Asset Retirement Obligations
Accounting standards for asset retirement obligationsAROs 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).Income. 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 when 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 theour Electric and Gas Utilities are valued using the market approach and include Level 2 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 Exchangeexchange settlement pricing for similar instruments.the applicable instrument. For over-the-counter swaps and options Level 2 assets and liabilities,instruments, fair value was derived from, or corroboratedobtained by utilizing a nationally recognized service that obtains observable market pricing data. In addition, theinputs to compute fair value, forwhich we validate by comparing our valuation with the over-the-counter swaps and option derivatives, if material, include a CVA component.counterparty. The CVA considers the fair value of the derivative and the probability of defaultthese swaps includes a CVA based on the lifecredit spreads of the contract. For the probability of a default component,counterparties when we utilize observable inputs supporting Level 2 disclosure by usingare in an unrealized gain position or on our own credit default spread if available, or a generic credit default spread curve that takes into account our credit ratings.when we are in an unrealized loss position.
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 UtilityUtilities’ 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 include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financingThese costs are presented on the balance sheet as an adjustment to the related debt liabilities.
Regulatory Accounting
Our regulated Electric Utilities and Gas Utilities followare subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. Our Electric and Gas Utilities account for income and expense items in accordance with 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.operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards:
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred
Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
If rate recovery becomes unlikely or uncertain due to competition orchanges in the regulatory action, these accounting standardsenvironment occur, we may no longer be eligible to apply which could require these net regulatory assetsthis accounting treatment, and may be required 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 followingeliminate regulatory assets and liabilities asfrom our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows.
As of December 31, (in thousands):
|
| | | | | | |
| | 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. |
Regulatory assets represent items2019 and 2018, 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 inhad total regulatory assets rather than in AOCI, including costs being amortized from the Aquilaof $271 million and SourceGas Transactions.
Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization$284 million respectively, and total regulatory liabilities of this asset is first offset by recognition of insurance proceeds$537 million 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.$541 million respectively. 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 recognition13 for further disclosure.information.
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-payingEach entity records both federal and state 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.ITCs. Under the flow-through method, investment tax creditsITCs 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 creditITC 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).Income.
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 or in Deferred income tax liabilities, net 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):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| | | | |
| Net income available for common stock | $ | 199,310 |
| $ | 258,442 |
| $ | 177,034 |
|
| | | | |
| Weighted average shares - basic | 60,662 |
| 54,420 |
| 53,221 |
|
| Dilutive effect of: | | | |
| Equity Units | — |
| 898 |
| 1,783 |
|
| Equity compensation | 136 |
| 168 |
| 116 |
|
| Weighted average shares - diluted | 60,798 |
| 55,486 |
| 55,120 |
|
| | | | |
| Net income available for common stock, per share - Diluted | $ | 3.28 |
| $ | 4.66 |
| $ | 3.21 |
|
|
| | | | | | | | | |
| | 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 |
|
The following outstanding securities were not included inexcluded from the computation of diluted earnings per share as their effect would have been anti-dilutivecomputation for the years ended December 31 because of their anti-dilutive nature (in thousands):
|
| | | | | | |
| | 2019 | 2018 | 2017 |
| | | | |
| Equity compensation | 1 |
| 16 |
| 11 |
|
| Anti-dilutive shares excluded from computation of earnings per share | 1 |
| 16 |
| 11 |
|
|
| | | | | | |
| | 2018 | 2017 | 2016 |
| | | | |
| Equity compensation | 16 |
| 11 |
| 3 |
|
| Anti-dilutive shares excluded from computation of earnings (loss) per share | 16 |
| 11 |
| 3 |
|
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,Simplifying the Accounting for Income Taxes, ASU 2016-022019-12
In February 2016,December 2019, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to recognize a right-of-use assetreduce costs and lease liability oncomplexity in applying accounting standards while maintaining or improving 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 useusefulness of the identified asset underinformation provided to users of the arrangement, which may result in changesfinancial statements. Amendments include removal of certain exceptions to the classificationgeneral principles of an arrangementASC 740, Income Taxes, and simplification in several other areas such as accounting for a lease.franchise tax (or similar tax) that is partially based on income. 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, 2018,2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows.
Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15
In JanuaryAugust 2018, the FASB issued amendmentsASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over 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 asterm of the arrangement. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of the year ofadoption. Early adoption with prior year comparative financial information and disclosures remaining as previously reported.
is permitted. We adopted this standard prospectively 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.2020. Adoption of this standardguidance 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, ASU 2017-04
In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairmentby 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 adoptionadopted this standard prospectively on January 1, 2020. Adoption of this guidance is not expected to have any impact on our financial position, results of operations or cash flows.
Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19
In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted.
We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for doubtful accounts, primarily associated with the inclusion of expected losses on unbilled revenue. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.
Recently Adopted Accounting Standards
Revenue from Contracts with Customers,Leases, ASU 2014-092016-02
Effective January 1, 2018, we adoptedIn February 2016, the FASB issued ASU 2014-09, Revenue from Contracts with Customers2016-02, Leases (Topic 606),842) to increase transparency and its related amendments (collectively known as ASC 606).comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under thisthe new standard, revenue is recognized when a customer obtains controldisclosures are required to meet the objective of promised goods or services in an amount that reflectsenabling users of financial statements to assess 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 contractsleases.
We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with customers.the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We appliedalso elected the five-step method outlinedpractical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements.
Adoption of the new standard resulted in the ASU to all in-scope revenue streamsrecording of an operating lease right-of-use asset of $3.1 million, an operating lease obligation liability of $3.2 million, and elected the modified retrospective implementation method. Implementationan accrued receivable of $4.5 million, as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million, which was recorded as an adjustment to retained earnings at January 1, 2019.
See Note 14 for additional details on leases.
Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 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. 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. Implementation
(2)REVENUE
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. Our primary types of revenue contracts are:
| |
| • | 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 tariff rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations 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 state or federal regulatory commissions 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, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. |
| |
| • | 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 supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered. |
| |
| • | Other non-regulated services - Our Electric and Gas 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. |
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 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 basisreporting segments, for the yearyears ended December 31, 2019 and 2018. Retrospective impactSales tax and other similar taxes are excluded from revenues.
|
| | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2019 | Electric Utilities | Gas Utilities | Power Generation | Mining | Inter-company Revenues | Total |
| Customer types: | (in thousands) |
| Retail | $ | 605,756 |
| $ | 817,840 |
| $ | — |
| $ | 59,233 |
| $ | (32,053 | ) | $ | 1,450,776 |
|
| Transportation | — |
| 143,390 |
| — |
| — |
| (1,042 | ) | 142,348 |
|
| Wholesale | 20,884 |
| — |
| 99,157 |
| — |
| (91,577 | ) | 28,464 |
|
| Market - off-system sales | 23,817 |
| 691 |
| — |
| — |
| (7,736 | ) | 16,772 |
|
| Transmission/Other | 57,104 |
| 47,725 |
| — |
| — |
| (16,797 | ) | 88,032 |
|
| Revenue from contracts with customers | 707,561 |
| 1,009,646 |
| 99,157 |
| 59,233 |
| (149,205 | ) | 1,726,392 |
|
| Other revenues | 5,191 |
| 384 |
| 2,101 |
| 2,396 |
| (1,564 | ) | 8,508 |
|
| Total revenues | $ | 712,752 |
| $ | 1,010,030 |
| $ | 101,258 |
| $ | 61,629 |
| $ | (150,769 | ) | $ | 1,734,900 |
|
|
|
|
|
|
|
|
| Timing of revenue recognition: |
|
|
|
|
|
|
| Services transferred at a point in time | $ | — |
| $ | — |
| $ | — |
| $ | 59,233 |
| $ | (32,053 | ) | $ | 27,180 |
|
| Services transferred over time | 707,561 |
| 1,009,646 |
| 99,157 |
| — |
| (117,152 | ) | 1,699,212 |
|
| Revenue from contracts with customers | $ | 707,561 |
| $ | 1,009,646 |
| $ | 99,157 |
| $ | 59,233 |
| $ | (149,205 | ) | $ | 1,726,392 |
|
|
| | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2018 | Electric Utilities | Gas Utilities | Power Generation (a) | Mining | Inter-company Revenues (a) | 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 |
| — |
| 90,791 |
| — |
| (84,957 | ) | 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 |
| 90,791 |
| 65,803 |
| (141,428 | ) | 1,748,542 |
|
| Other revenues | 2,427 |
| 955 |
| 1,660 |
| 2,230 |
| (1,546 | ) | 5,726 |
|
| Total revenues | $ | 711,451 |
| $ | 1,025,307 |
| $ | 92,451 |
| $ | 68,033 |
| $ | (142,974 | ) | $ | 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 |
| 90,791 |
| — |
| (109,234 | ) | 1,714,933 |
|
| Revenue from contracts with customers | $ | 709,024 |
| $ | 1,024,352 |
| $ | 90,791 |
| $ | 65,803 |
| $ | (141,428 | ) | $ | 1,748,542 |
|
| |
| (a) | Due to the changes in our segment disclosures discussed in Note 5, Power Generation Wholesale revenue was revised for the year ended December 31, 2018, which resulted in an increase of $38 million. The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million. There was no impact to our consolidated Total 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 and therefore prior year presentation was not changed. Forfor our rate-regulated entities,revenue contracts. We are the principal in our revenue contracts, as we capitalizehave control over 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 yearsservices 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.
(2) ACQUISITION
Acquisition of SourceGas
On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuantservices being transferred to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, including the assumptioncustomer.
Revenue Not in Scope 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.ASC 606
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 millionabove include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, derivative revenue under ASC 815 and
alternative revenue programs revenue under ASC 980. Effective January 1, 2019, we changed how we account for the PPA between Black Hills Colorado IPP and Colorado Electric at the segment level and now recognize on an accrual basis, rather than a
working capital adjustment received of approximately $11 million, resulted in goodwill of $940 million. We had up to one year fromfinance lease. See Note 5 for additional information.
Significant Judgments and Estimates
Unbilled Revenue
To 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 millionextent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the goodwillrevenue 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 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.
|
| | | | | |
| | (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 |
|
Conditions of SourceGas Acquisition Regulatory Approval
The acquisition was subject to regulatory approvals from the public utility commissionsour Accounts Receivable further discussed in
Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC)Note 1. 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:
|
| | | |
| | 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 |
|
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 associatedtypically incur 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,be capitalized to obtain or that may be obtained in the future.fulfill a contract.
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.
(3) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31 consisted of the following (dollars in thousands):
| | | | 2018 | 2017 | Lives (in years) | 2019 | 2018 | 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 | Property, Plant and Equipment | Weighted Average Useful Life (in years) | Property, Plant and Equipment (b) | Weighted Average Useful Life (in years) | Minimum | Maximum |
| | | | | | | | | |
| Electric plant: | | | | | | | | |
| Production | $ | 1,318,643 |
| 41 | $ | 1,315,044 |
| 39 | 32 | 46 | $ | 1,348,049 |
| 41 | $ | 1,318,643 |
| 41 | 32 | 46 |
| Electric transmission | 437,082 |
| 51 | 407,203 |
| 51 | 48 | 53 | 483,640 |
| 51 | 437,082 |
| 51 | 43 | 54 |
| Electric distribution | 793,725 |
| 48 | 755,213 |
| 48 | 45 | 50 | 861,042 |
| 47 | 793,725 |
| 48 | 46 | 50 |
Plant acquisition adjustment (a) | 4,870 |
| 32 | 4,870 |
| 32 | 4,870 |
| 32 | 4,870 |
| 32 |
| General | 233,531 |
| 28 | 232,842 |
| 31 | 26 | 28 | 259,266 |
| 28 | 233,531 |
| 28 | 26 | 33 |
Capital lease - plant in service (b) | 261,441 |
| 20 | 261,441 |
| 20 | |
| Total electric plant in service | 3,049,292 |
| | 2,976,613 |
| | 2,956,867 |
| | 2,787,851 |
| |
| Construction work in progress | 60,480 |
| | 13,595 |
| | 102,268 |
| | 60,480 |
| |
| Total electric plant | 3,109,772 |
| | 2,990,208 |
| | 3,059,135 |
| | 2,848,331 |
| |
| Less accumulated depreciation and amortization | 706,869 |
| | 644,022 |
| | (670,861 | ) | | (615,365 | ) | |
| Electric plant net of accumulated depreciation and amortization | $ | 2,402,903 |
| | $ | 2,346,186 |
| | $ | 2,388,274 |
| | $ | 2,232,966 |
| |
_____________
| |
| (a) | The plant acquisition adjustment is included in rate base and is being recovered with 1211 years remaining. |
| |
| (b) | Capital lease -Due to the changes in our segment disclosures discussed in Note 5, Total electric plant in service, represents the assets accounted forAccumulated depreciation and amortization, and Electric plant net of accumulated depreciation and amortization were revised 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 which resulted in an increase (decrease) of ($261) million, $91 million and ($170) million, respectively. There was no impact on our consolidated Plant, property and equipment. |
| | | | 2018 | 2017 | Lives (in years) | 2019 | 2018 | 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 | 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 | $ | 13,000 |
| 35 | $ | 13,580 |
| 35 | 24 | 71 |
| Gas transmission | 423,873 |
| 48 | 366,433 |
| 48 | 22 | 66 | 516,172 |
| 50 | 423,873 |
| 48 | 22 | 67 |
| Gas distribution | 1,595,644 |
| 42 | 1,413,431 |
| 42 | 33 | 47 | 1,857,233 |
| 43 | 1,595,644 |
| 42 | 30 | 56 |
Cushion gas - depreciable (a) | 3,539 |
| 28 | 3,539 |
| 28 | 3,539 |
| 28 | 3,539 |
| 28 |
Cushion gas - not depreciated (a) | 46,369 |
| N/A | 47,466 |
| N/A | |
Cushion gas - not depreciable (a) | | 44,443 |
| N/A | 46,369 |
| N/A |
| Storage | 29,335 |
| 30 | 28,520 |
| 31 | 28 | 38 | 46,977 |
| 31 | 29,335 |
| 30 | 27 | 49 |
| General | 355,920 |
| 19 | 336,869 |
| 19 | 10 | 24 | 437,054 |
| 20 | 355,920 |
| 19 | 10 | 24 |
| Total gas plant in service | 2,468,260 |
| | 2,206,753 |
| | 2,918,418 |
| | 2,468,260 |
| |
| Construction work in progress | 38,271 |
| | 44,440 |
| | 63,080 |
| | 38,271 |
| |
| Total gas plant | 2,506,531 |
| | 2,251,193 |
| | 2,981,498 |
| | 2,506,531 |
| |
| Less accumulated depreciation and amortization | 279,580 |
| | 229,170 |
| | (336,721 | ) | | (279,580 | ) | |
| Gas plant net of accumulated depreciation and amortization | $ | 2,226,951 |
| | $ | 2,022,023 |
| | $ | 2,644,777 |
| | $ | 2,226,951 |
| |
_____________
| |
| (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 cushionCushion gas is determined by the respective regulatory jurisdiction in which the cushionCushion gas resides. |
|
| | | | | | | | | | | | | | | | | | |
| 2019 | 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 | $ | 532,397 |
| $ | 2,121 |
| $ | 534,518 |
| $ | (154,362 | ) | $ | 380,156 |
| 31 | 2 | 40 |
| Mining | $ | 179,198 |
| $ | 1,275 |
| $ | 180,473 |
| $ | (118,585 | ) | $ | 61,888 |
| 13 | 2 | 59 |
| | | 2018 | 2018 | Lives (in years) | 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 | 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 | $ | 435,438 |
| $ | 11,796 |
| $ | 447,234 |
| $ | (137,832 | ) | $ | 309,402 |
| 31 | 2 | 40 |
| Mining | $ | 175,650 |
| $ | — |
| $ | 175,650 |
| $ | 111,689 |
| $ | 63,961 |
| 13 | 2 | 59 | $ | 175,650 |
| $ | — |
| $ | 175,650 |
| $ | (111,689 | ) | $ | 63,961 |
| 13 | 2 | 59 |
_____________
| |
| (a) | Due to the changes in our segment disclosures discussed in Note 5, Property, plant and equipment, Accumulated depreciation and amortization, and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of $261 million, ($73) million and $188 million, respectively. There was no impact on our consolidated Plant, property and equipment. |
|
| | | | | | | | | | | | | | | | | | |
| 2019 | 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 |
| Corporate | $ | 5,721 |
| $ | 23,334 |
| $ | 29,055 |
| $ | (964 | ) | $ | 28,091 |
| 10 | 3 | 30 |
|
| | | | | | | | | | | | | | | | | | |
| 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 | 2018 | Lives (in years) | 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 | Property, Plant and Equipment | Construction Work in Progress | Total Property Plant and Equipment | Less Accumulated Depreciation and Amortization | 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 | $ | 5,721 |
| $ | 16,548 |
| $ | 22,269 |
| $ | (670 | ) | $ | 21,599 |
| 8 | 3 | 30 |
___________
| |
| (a) | ReflectsDue to the eliminationchanges in our segment disclosures discussed in Note 5, Corporate Accumulated depreciation and amortization and Net property, plant and equipment were revised as of the capital lease accumulated depreciation difference between Colorado ElectricDecember 31, 2018 which resulted in an increase (decrease) of ($18) million and Black Hills Colorado IPP of $18 million.($18) million respectively. There was no impact on our consolidated Plant, property and equipment. |
|
| | | | | | | | | | | | | | | | | | | | | |
| 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. |
(4) 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).Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.
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.regions. 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 coalfuel 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. |
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.
At December 31, 20182019, our interests in jointly-owned generating facilities and transmission systems were (in thousands):
|
| | | | | | | | | | | | |
| | Plant in Service | Construction Work in Progress | Less Accumulated Depreciation | Plant Net of Accumulated Depreciation |
| Wyodak Plant | $ | 116,074 |
| $ | 729 |
| $ | (64,413 | ) | $ | 52,390 |
|
| Transmission Tie | $ | 19,862 |
| $ | 4,161 |
| $ | (6,612 | ) | $ | 17,411 |
|
| Wygen I | $ | 120,824 |
| $ | 289 |
| $ | (48,703 | ) | $ | 72,410 |
|
| Wygen III | $ | 146,161 |
| $ | 400 |
| $ | (25,518 | ) | $ | 121,043 |
|
|
| | | | | | | | | |
| | 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 |
|
Jointly Owned facilityFacility - 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 provideprovides its share of energy from the wind farm to Colorado Electric through a new PPA, which replaces the PPA Colorado Electric had with AltaGas, expiringexpires in October 2037.
(5) 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.
Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance. Effective January 1, 2019, we concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance. The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment performance.
Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments and Corporate and Other included the impacts of finance lease accounting relating to Colorado Electric’s PPA with Black Hills Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Black Hills Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment).
The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. Effective January 1, 2019, we changed how we account for this PPA at the segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no revisions to Gas Utilities and Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets.
Segment information was as follows (in thousands):
| | | Total Assets (net of intercompany eliminations) as of December 31, | 2018 | 2017 | 2019 | 2018 |
Electric (a) | $ | 2,895,577 |
| $ | 2,906,275 |
| |
| Gas | 3,623,475 |
| 3,426,466 |
| |
Electric Utilities (a) | | $ | 2,900,983 |
| $ | 2,707,695 |
|
| Gas Utilities | | 4,032,339 |
| 3,623,475 |
|
Power Generation (a) | 154,203 |
| 60,852 |
| 417,715 |
| 342,085 |
|
| Mining | 80,594 |
| 65,455 |
| 77,175 |
| 80,594 |
|
| Corporate and Other | 209,478 |
| 115,612 |
| 130,245 |
| 209,478 |
|
Discontinued operations (b) | — |
| 84,242 |
| |
| Total assets | $ | 6,963,327 |
| $ | 6,658,902 |
| $ | 7,558,457 |
| $ | 6,963,327 |
|
__________________
| |
| (a) | The PPA under which Black Hills Colorado IPP provides generationDue to support Coloradothe changes in our segment disclosures, Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by ourUtilities and Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. |
| |
(b) | On November 1, 2017, the BHC BoardTotal assets were revised as of Directors approved a complete divestitureDecember 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on our Oil and Gas segment. See Note 21 for additional information.consolidated Total assets. |
| | Capital Expenditures (a) for the years ended December 31, | 2018 | 2017 | 2019 | 2018 |
| Capital expenditures | | |
| Electric Utilities | $ | 152,524 |
| $ | 138,060 |
| $ | 222,911 |
| $ | 152,524 |
|
| Gas Utilities | 288,438 |
| 184,389 |
| 512,366 |
| 288,438 |
|
| Power Generation | 30,945 |
| 1,864 |
| 85,346 |
| 30,945 |
|
| Mining | 18,794 |
| 6,708 |
| 8,430 |
| 18,794 |
|
| Corporate and Other | 11,723 |
| 6,668 |
| 20,702 |
| 11,723 |
|
| Total capital expenditures of continuing operations | 502,424 |
| 337,689 |
| 849,755 |
| 502,424 |
|
| Total capital expenditures of discontinued operations | 2,402 |
| 23,222 |
| — |
| 2,402 |
|
| Total capital expenditures | $ | 504,826 |
| $ | 360,911 |
| $ | 849,755 |
| $ | 504,826 |
|
_________________
| |
| (a) | Includes accruals for property, plant and equipment.equipment as disclosed in Note 17. |
| | | Property, Plant and Equipment as of December 31, | 2018 | 2017 | 2019 | 2018 |
Electric Utilities (a) | $ | 3,109,772 |
| $ | 2,990,208 |
| $ | 3,059,135 |
| $ | 2,848,331 |
|
| Gas Utilities | 2,506,531 |
| 2,251,193 |
| 2,981,498 |
| 2,506,531 |
|
Power Generation (a) | 185,793 |
| 155,793 |
| 534,518 |
| 447,234 |
|
| Mining | 175,650 |
| 158,370 |
| 180,473 |
| 175,650 |
|
| Corporate and Other | 22,269 |
| 11,954 |
| 29,055 |
| 22,269 |
|
| Total property, plant and equipment | $ | 6,000,015 |
| $ | 5,567,518 |
| $ | 6,784,679 |
| $ | 6,000,015 |
|
_______________
| |
| (a) | The PPA under which Black Hills Colorado IPP provides generationDue to support Coloradothe changes in our segment disclosures, Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by ourUtilities and Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.Property, Plant and Equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million and $261 million, respectively. There was no impact on our consolidated Property, Plant and Equipment. |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Consolidating Income Statement |
| Year ended December 31, 2019 | Electric Utilities | Gas Utilities | Power Generation | Mining | Corporate | Inter-Company Eliminations | Total |
| |
|
| Revenue - |
|
|
|
|
|
|
|
| Contracts with customers | $ | 684,445 |
| $ | 1,007,187 |
| $ | 7,580 |
| $ | 27,180 |
| $ | — |
| $ | — |
| $ | 1,726,392 |
|
| Other revenues | 5,191 |
| 384 |
| 1,859 |
| 1,074 |
| — |
| — |
| 8,508 |
|
| | 689,636 |
| 1,007,571 |
| 9,439 |
| 28,254 |
| — |
| — |
| 1,734,900 |
|
| Inter-company operating revenue - |
|
|
|
|
|
|
|
| Contracts with customers | 23,116 |
| 2,459 |
| 91,577 |
| 32,053 |
| 230 |
| (149,435 | ) | — |
|
| Other revenues | — |
| — |
| 242 |
| 1,322 |
| 343,975 |
| (345,539 | ) | — |
|
| | 23,116 |
| 2,459 |
| 91,819 |
| 33,375 |
| 344,205 |
| (494,974 | ) | — |
|
| Total revenue | 712,752 |
| 1,010,030 |
| 101,258 |
| 61,629 |
| 344,205 |
| (494,974 | ) | 1,734,900 |
|
| | | | | | | | |
| Fuel, purchased power and cost of natural gas sold | 268,297 |
| 425,898 |
| 9,059 |
| — |
| 268 |
| (132,693 | ) | 570,829 |
|
| Operations and maintenance | 195,581 |
| 301,844 |
| 28,429 |
| 40,032 |
| 286,799 |
| (303,776 | ) | 548,909 |
|
| Depreciation, depletion and amortization | 88,577 |
| 92,317 |
| 18,991 |
| 8,970 |
| 22,065 |
| (21,800 | ) | 209,120 |
|
| Adjusted operating income (loss) | $ | 160,297 |
| $ | 189,971 |
| $ | 44,779 |
| $ | 12,627 |
| $ | 35,073 |
| $ | (36,705 | ) | $ | 406,042 |
|
| | | | | | | | |
| Interest expense, net | | | | | | | (137,659 | ) |
Impairment of investment (a) | | | | | | | (19,741 | ) |
| Other income (expense), net | | | | | | | (5,740 | ) |
| Income tax benefit (expense) | | | | | | | (29,580 | ) |
| Income from continuing operations | | | | | | | 213,322 |
|
| (Loss) from discontinued operations, net of tax | | | | | | | — |
|
| Net income | | | | | | | 213,322 |
|
| Net income attributable to noncontrolling interest | | | | | | | (14,012 | ) |
| Net income available for common stock | | | | | | | $ | 199,310 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 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) | In 2019 we recorded an impairment of our investment in equity securities of a privately held oil and gas company. See Note 1 for additional information. |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Consolidating Income Statement |
| Year ended December 31, 2018 | Electric Utilities (b) | Gas Utilities | Power Generation (b) | Mining | Corporate | Inter-Company Eliminations (b) | 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 |
| 84,959 |
| 32,194 |
| 148 |
| (141,577 | ) | — |
|
| Other revenues | — |
| — |
| 246 |
| 1,299 |
| 379,775 |
| (381,320 | ) | — |
|
| | 22,752 |
| 1,524 |
| 85,205 |
| 33,493 |
| 379,923 |
| (522,897 | ) | — |
|
| Total revenue | 711,451 |
| 1,025,307 |
| 92,451 |
| 68,033 |
| 379,923 |
| (522,897 | ) | 1,754,268 |
|
| | | | | | | | |
| Fuel, purchased power and cost of natural gas sold | 283,840 |
| 462,153 |
| 8,592 |
| — |
| 44 |
| (129,019 | ) | 625,610 |
|
| Operations and maintenance | 186,175 |
| 291,481 |
| 25,135 |
| 43,728 |
| 324,916 |
| (336,142 | ) | 535,293 |
|
| Depreciation, depletion and amortization | 85,567 |
| 86,434 |
| 16,110 |
| 7,965 |
| 21,161 |
| (20,909 | ) | 196,328 |
|
| Adjusted operating income (loss) | 155,869 |
| 185,239 |
| 42,614 |
| 16,340 |
| 33,802 |
| (36,827 | ) | 397,037 |
|
| |
|
|
|
|
|
|
|
| Interest expense, net | | | | | | | (139,975 | ) |
| Other income (expense), net | | | | | | | (1,180 | ) |
Income tax benefit (expense) (a) | | | | | | | 23,667 |
|
| Income from continuing operations | | | | | | | 279,549 |
|
| (Loss) from discontinued operations, net of tax | | | | | | | (6,887 | ) |
| Net income | | | | | | | 272,662 |
|
| Net income attributable to noncontrolling interest | | | | | | | (14,220 | ) |
| Net income available for common stock | | | | | | | $ | 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 15.15. |
| |
| (b) | Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2018, which resulted in an increase (decrease) as follows (in millions): |
|
| | | | | | | | | | | | |
| Year ended December 31, 2018 | Electric Utilities | Power Generation | Inter-Company Eliminations | Total |
| Inter-company operating revenue - Contracts with customers | $ | — |
| $ | 3.5 |
| $ | (3.5 | ) | $ | — |
|
| Fuel, purchased power and cost of natural gas sold | 6.7 |
| — |
| (6.7 | ) | — |
|
| Depreciation, depletion and amortization | (13.1 | ) | 9.2 |
| 3.9 |
| — |
|
| Adjusted operating income (loss) | $ | 6.4 |
| $ | (5.7 | ) | $ | (0.7 | ) | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Consolidating Income Statement |
| Year ended December 31, 2017 | Electric Utilities (b) | Gas Utilities | Power Generation (b) | Mining | Corporate | Inter-Company Eliminations (b) | Total |
| | |
| Revenue | $ | 689,945 |
| $ | 947,595 |
| $ | 7,263 |
| $ | 35,463 |
| $ | — |
| $ | — |
| $ | 1,680,266 |
|
| Inter-company revenue | 14,705 |
| 35 |
| 87,357 |
| 31,158 |
| 344,685 |
| (477,940 | ) | — |
|
| Total revenue | 704,650 |
| 947,630 |
| 94,620 |
| 66,621 |
| 344,685 |
| (477,940 | ) | 1,680,266 |
|
| | | | | | | | |
| Fuel, purchased power and cost of natural gas sold | 274,363 |
| 409,603 |
| 9,340 |
| — |
| 151 |
| (130,169 | ) | 563,288 |
|
| Operations and maintenance | 172,307 |
| 269,190 |
| 23,042 |
| 44,882 |
| 296,067 |
| (293,492 | ) | 511,996 |
|
| Depreciation, depletion and amortization | 80,243 |
| 83,732 |
| 15,548 |
| 8,239 |
| 21,031 |
| (20,547 | ) | 188,246 |
|
| Adjusted operating income (loss) | 177,737 |
| 185,105 |
| 46,690 |
| 13,500 |
| 27,436 |
| (33,732 | ) | 416,736 |
|
| |
|
|
|
|
|
|
|
| Interest expense, net | | | | | | | (137,102 | ) |
| Other income (expense), net | | | | | | | 2,108 |
|
| Income tax benefit (expense) | | | | | | | (73,367 | ) |
| Income from continuing operations | | | | | | | 208,375 |
|
(Loss) from discontinued operations, net of tax(a) | | | | | | | (17,099 | ) |
| Net income | | | | | | | 191,276 |
|
| Net income attributable to noncontrolling interest | | | | | | | (14,242 | ) |
| Net income available for common stock | | | | | | | $ | 177,034 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 21.21. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 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)(b) | Discontinued operations includes oilDue to changes in our segment disclosures, Adjusted operating income and gas property impairments. See Note 21.related income statement accounts were revised for the year ended December 31, 2017, which resulted in an increase (decrease) as follows (in millions): |
|
| | | | | | | | | | | | |
| Year ended December 31, 2017 | Electric Utilities | Power Generation | Inter-Company Eliminations | Total |
| Inter-company revenue | $ | — |
| $ | 3.1 |
| $ | (3.1 | ) | $ | — |
|
| Fuel, purchased power and cost of natural gas sold | 6.0 |
| — |
| (6.0 | ) | — |
|
| Depreciation, depletion and amortization | (13.1 | ) | 9.6 |
| 3.5 |
| — |
|
| Adjusted operating income (loss) | $ | 7.1 |
| $ | (6.5 | ) | $ | (0.6 | ) | $ | — |
|
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):
|
| | | | | | |
| | 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. |
(6) LONG-TERM DEBT
Long-term debt outstanding was as follows (dollars in thousands):
| |
|
| Interest Rate at | Balance Outstanding |
| Interest Rate at | Balance Outstanding |
| | Due Date | December 31, 2018 | December 31, 2018 | December 31, 2017 | Due Date | December 31, 2019 | December 31, 2019 | December 31, 2018 |
| Corporate | | | | |
| Senior unsecured notes due 2023 | November 30, 2023 | 4.25% | $ | 525,000 |
| $ | 525,000 |
| November 30, 2023 | 4.25% | $ | 525,000 |
| $ | 525,000 |
|
| Senior unsecured notes due 2020 | July 15, 2020 | 5.88% | 200,000 |
| 200,000 |
| July 15, 2020 | N/A | — |
| 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 |
| January 15, 2026 | 3.95% | 300,000 |
| 300,000 |
|
| Senior unsecured notes due 2027 | January 15, 2027 | 3.15% | 400,000 |
| 400,000 |
| January 15, 2027 | 3.15% | 400,000 |
| 400,000 |
|
| Senior unsecured notes due 2033 | May 1, 2033 | 4.35% | 400,000 |
| — |
| May 1, 2033 | 4.35% | 400,000 |
| 400,000 |
|
| Senior unsecured notes, due 2046 | September 15, 2046 | 4.20% | 300,000 |
| 300,000 |
| 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 |
| — |
| |
| Senior unsecured notes, due 2029 | | October 15, 2029 | 3.05% | 400,000 |
| — |
|
| Senior unsecured notes, due 2049 | | October 15, 2049 | 3.88% | 300,000 |
| — |
|
Corporate term loan due 2021 (a) | | June 17, 2021 | N/A | — |
| 300,000 |
|
| Corporate term loan due 2021 | June 7, 2021 | 2.32% | 12,921 |
| 18,664 |
| June 7, 2021 | 2.32% | 7,178 |
| 12,921 |
|
| Total Corporate debt | | 2,437,921 |
| 2,592,664 |
| | 2,632,178 |
| 2,437,921 |
|
| Less unamortized debt discount | | (5,122 | ) | (3,808 | ) | | (6,462 | ) | (5,122 | ) |
| Total Corporate debt, net | | 2,432,799 |
| 2,588,856 |
| | 2,625,716 |
| 2,432,799 |
|
| | | | | |
| 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 |
| |
| South Dakota Electric | | | |
Series 94A Debt, variable rate (b) | | June 1, 2024 | 1.84% | 2,855 |
| 2,855 |
|
| First Mortgage Bonds due 2032 | August 15, 2032 | 7.23% | 75,000 |
| 75,000 |
| August 15, 2032 | 7.23% | 75,000 |
| 75,000 |
|
| First Mortgage Bonds due 2039 | November 1, 2039 | 6.13% | 180,000 |
| 180,000 |
| November 1, 2039 | 6.13% | 180,000 |
| 180,000 |
|
| First Mortgage Bonds due 2044 | | October 20, 2044 | 4.43% | 85,000 |
| 85,000 |
|
| Total South Dakota Electric debt | | | 342,855 |
| 342,855 |
|
| Less unamortized debt discount | | | (82 | ) | (86 | ) |
| Total South Dakota Electric debt, net | | | 342,773 |
| 342,769 |
|
| | | | |
| Wyoming Electric | | | |
Industrial development revenue bonds due 2021(a) | | September 1, 2021 | 1.68% | 7,000 |
| 7,000 |
|
Industrial development revenue bonds due 2027(a) | | March 1, 2027 | 1.68% | 10,000 |
| 10,000 |
|
| First Mortgage Bonds due 2037 | November 20, 2037 | 6.67% | 110,000 |
| 110,000 |
| 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 |
| |
| First Mortgage Bonds due 2044 | | October 20, 2044 | 4.53% | 75,000 |
| 75,000 |
|
| Total Wyoming Electric debt | | | 202,000 |
| 202,000 |
|
| Less unamortized debt discount | | (86 | ) | (90 | ) | | — |
| — |
|
| Total Electric Utilities debt, net | | 544,769 |
| 544,765 |
| |
| Total Wyoming Electric debt, net | | | 202,000 |
| 202,000 |
|
| | | | | |
| Total long-term debt | | 2,977,568 |
| 3,133,621 |
| | 3,170,489 |
| 2,977,568 |
|
| Less current maturities | | 5,743 |
| 5,743 |
| | 5,743 |
| 5,743 |
|
Less unamortized deferred financing costs (d) | | 20,990 |
| 18,478 |
| |
Less unamortized deferred financing costs (b) | | | 24,650 |
| 20,990 |
|
| Long-term debt, net of current maturities and deferred financing costs | | $ | 2,950,835 |
| $ | 3,109,400 |
| | $ | 3,140,096 |
| $ | 2,950,835 |
|
_______________
| |
| (a) | Variable interest rate, based on LIBOR plus a spread.rate. |
| |
| (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$1.7 million and $1.7$2.3 million as of December 31, 20182019 and December 31, 2017,2018, respectively. |
Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands):
|
| | | |
| 2020 | $ | 5,743 |
|
| 2021 | $ | 8,435 |
|
| 2022 | $ | — |
|
| 2023 | $ | 525,000 |
|
| 2024 | $ | 2,855 |
|
| Thereafter | $ | 2,635,000 |
|
|
| | | |
| 2019 | $ | 5,743 |
|
| 2020 | $ | 505,743 |
|
| 2021 | $ | 8,435 |
|
| 2022 | $ | — |
|
| 2023 | $ | 525,000 |
|
| Thereafter | $ | 1,937,855 |
|
Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2018.2019.
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 October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured noted. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029 and $300 million of 3.875% 30-year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following:
• Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021;
• Retire the $200 million 5.875% senior notes due July 15, 2020; and
• Repay a portion of short-term debt.
On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan.
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 May 1, 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 newthe $400 million 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)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 onhad a maturity date of July 30, 2020 and hashad substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The interest cost associated with thisThis term loan is determined based upon our corporate credit ratingwas later amended on June 17, 2019 and then repaid using proceeds 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, atOctober 3, 2019 public debt offering.
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):
|
| | | | | | | | | | | | |
| Deferred Financing Costs Remaining at | | Amortization Expense for the years ended December 31, |
| December 31, 2019 | | 2019 | 2018 | 2017 |
| $ | 24,650 |
| | $ | 3,242 |
| $ | 2,829 |
| $ | 3,349 |
|
|
| | | | | | | | | | | | |
| 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 |
|
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, 2018,2019, 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, 20182019:
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, 2018,2019, the restricted net assets at our Electric and Gas Utilities were approximately $257$156 million.
Wyoming Electric and South Dakota Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements.
(7) 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):
|
| | | | | | | | | | | | |
| | December 31, 2019 | December 31, 2018 |
| | Balance Outstanding | Letters of Credit (a) | Balance Outstanding | Letters of Credit (a) |
| Revolving Credit Facility | $ | — |
| $ | 30,274 |
| $ | — |
| $ | 22,311 |
|
| CP Program | 349,500 |
| — |
| 185,620 |
| — |
|
| Total | $ | 349,500 |
| $ | 30,274 |
| $ | 185,620 |
| $ | 22,311 |
|
|
| | | | | | |
| | Balance Outstanding at |
| | December 31, 2018 | December 31, 2017 |
| CP Program | $ | 185,620 |
| $ | 211,300 |
|
| |
| (a) | Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility. |
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-year2 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, 20182019. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 20182019. 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 short-term borrowings (payments) under the CP Program during 20182019 were $(26) million and our notes outstanding as of December 31, 2018 were $186$164 million. As of December 31, 2018,2019, the weighted average interest rate on CP Programshort-term borrowings was 2.88%2.03%.
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).Income. 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 Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and our Term Loans requireaccelerate all principal and interest outstanding. As of December 31, 2019, we were in compliance with the following financial covenant at the end of each quarter:these covenants.
|
| | | | | | |
| | At December 31, 2018 | | Covenant Requirement at December 31, 2018 |
| Consolidated Indebtedness to Capitalization Ratio | 59 | % | | Less than | 65 | % |
(8) 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, and an evaporation pond andat our Electric Utilities, wind turbines at the regulatedour Electric Utilities segment,and Power Generation segments, retirement of gas pipelines at our Gas Utilities and removal of asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these asset retirement obligations.AROs. 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):
| | | | December 31, 2017 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates (b) | December 31, 2018 | December 31, 2018 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates (a) (b) | December 31, 2019 |
Electric Utilities | $ | 6,287 |
| $ | — |
| $ | — |
| $ | 269 |
| $ | 2 |
| $ | 6,558 |
| $ | 6,258 |
| $ | — |
| $ | — |
| $ | 385 |
| $ | 2,686 |
| $ | 9,329 |
|
| Gas Utilities | 33,238 |
| 152 |
| — |
| 1,237 |
| — |
| 34,627 |
| 34,627 |
| — |
| — |
| 1,458 |
| — |
| 36,085 |
|
Power Generation (c) | | 300 |
| 3,445 |
| — |
| 158 |
| 836 |
| 4,739 |
|
| Mining | 12,499 |
| — |
| (4 | ) | 649 |
| 2,471 |
| 15,615 |
| 15,615 |
| — |
| (380 | ) | 740 |
| (1,923 | ) | 14,052 |
|
| Total | $ | 52,024 |
| $ | 152 |
| $ | (4 | ) | $ | 2,155 |
| $ | 2,473 |
| $ | 56,800 |
| $ | 56,800 |
| $ | 3,445 |
| $ | (380 | ) | $ | 2,741 |
| $ | 1,599 |
| $ | 64,205 |
|
| | | | December 31, 2016 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates (a) | December 31, 2017 | December 31, 2017 | Liabilities Incurred | Liabilities Settled | Accretion | Revisions to Prior Estimates (b) | December 31, 2018 |
| Electric Utilities | $ | 4,661 |
| $ | — |
| $ | (4 | ) | $ | 268 |
| $ | 1,362 |
| $ | 6,287 |
| $ | 6,287 |
| $ | — |
| $ | — |
| $ | 269 |
| $ | 2 |
| $ | 6,558 |
|
| Gas Utilities | 29,775 |
| — |
| — |
| 1,142 |
| 2,321 |
| 33,238 |
| 33,238 |
| 152 |
| — |
| 1,237 |
| — |
| 34,627 |
|
| Mining | 12,440 |
| — |
| (107 | ) | 651 |
| (485 | ) | 12,499 |
| 12,499 |
| — |
| (4 | ) | 649 |
| 2,471 |
| 15,615 |
|
| Total | $ | 46,876 |
| $ | — |
| $ | (111 | ) | $ | 2,061 |
| $ | 3,198 |
| $ | 52,024 |
| $ | 52,024 |
| $ | 152 |
| $ | (4 | ) | $ | 2,155 |
| $ | 2,473 |
| $ | 56,800 |
|
_____________________
| |
| (a) | The Gas Utilities’ Revisionincrease in Electric Utilities Revisions to Prior Estimates represents our legal liability for retirement of gas pipelines, specificallywas primarily driven by an increase to purge and cap these lines in accordance with Federal regulations.the estimated cost to decommission certain regulated wind farm assets. |
| |
| (b) | The increasechanges in the Mining Revision to Prior Estimates waswere primarily driven by higherchanges in estimated costs associated with back-filling the pit with overburden removed during the mining process. |
| |
| (c) | We reclassified $0.3 million of ARO as of December 31, 2018 related to Busch Ranch I from Electric Utilities to the Power Generation segment as a result of Black Hills Electric Generation’s purchase of its 50% ownership interest in Busch Ranch I. Additional liabilities were incurred in 2019 from new wind assets. |
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.
(9) 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:
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. |
Interest rate risk associated with our variable debt.
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, 20182019 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).Income.
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 20192020 through December 2020.2021. 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:
|
| | | | | | |
| | December 31, 2019 | December 31, 2018 |
| | Notional (MMBtus) | Maximum Term (months) (a) | Notional (MMBtus) | Maximum Term (months) (a) |
| Natural gas futures purchased | 1,450,000 |
| 12 | 4,000,000 |
| 24 |
| Natural gas options purchased, net | 3,240,000 |
| 3 | 4,320,000 |
| 13 |
| Natural gas basis swaps purchased | 1,290,000 |
| 12 | 3,960,000 |
| 24 |
Natural gas over-the-counter swaps, net (b) | 4,600,000 |
| 24 | 3,660,000 |
| 24 |
Natural gas physical commitments, net (c) | 13,548,235 |
| 12 | 18,325,852 |
| 30 |
|
| | | | | | |
| | 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, 1,542,0002019, 1,415,000 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. |
Based on December 31, 20182019 prices, a $0.4$0.5 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, 2019, 2018 2017 and 20162017 (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.
| | | | December 31, 2018 | December 31, 2019 |
| 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) | Location of Reclassifications from AOCI into Income | Amount of Gain/(Loss) Reclassified from AOCI into Income |
| | | | | | | |
| Interest rate swaps | Interest expense | $ | (2,851 | ) | Interest expense | $ | — |
| Interest expense | $ | (2,851 | ) |
| Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (130 | ) | Fuel, purchased power and cost of natural gas sold | — |
| Fuel, purchased power and cost of natural gas sold | 417 |
|
| Total impact from cash flow hedges | | $ | (2,981 | ) | | $ | — |
| | $ | (2,434 | ) |
| | | | December 31, 2017 | 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) | Location of Reclassifications from AOCI into Income | Amount of Gain/(Loss) Reclassified from AOCI into Income |
| | | | | | | |
| Interest rate swaps | Interest expense | $ | (2,941 | ) | Interest expense | $ | — |
| Interest expense | $ | (2,851 | ) |
| Commodity derivatives | Net (loss) from discontinued operations | 913 |
| Net (loss) from discontinued operations | — |
| Fuel, purchased power and cost of natural gas sold | (130 | ) |
| 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 | ) | |
| Total impact from cash flow hedges | | | $ | (2,981 | ) |
| | | | December 31, 2016 | 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) | Location of Reclassifications from AOCI into Income | Amount of Gain/(Loss) Reclassified from AOCI into Income |
| | | | | | | |
| Interest rate swaps | Interest expense | $ | (3,899 | ) | Interest expense | $ | (953 | ) | Interest expense | $ | (2,941 | ) |
| Commodity derivatives | Net (loss) from discontinued operations | 11,019 |
| Net (loss) from discontinued operations | — |
| Net (loss) from discontinued operations | 913 |
|
| Commodity derivatives | Fuel, purchased power and cost of natural gas sold | (14 | ) | Fuel, purchased power and cost of natural gas sold | — |
| Fuel, purchased power and cost of natural gas sold | (243 | ) |
| Total | | $ | 7,106 |
| | $ | (953 | ) | |
| Total impact from cash flow hedges | | | $ | (2,271 | ) |
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, 2019, 2018 and 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.(in thousands).
|
| | | | | | | | | |
| | December 31, 2019 | December 31, 2018 | December 31, 2017 |
| | |
| Increase (decrease) in fair value: | | | |
| Forward commodity contracts | $ | (548 | ) | $ | 983 |
| $ | 366 |
|
| Recognition of (gains) losses in earnings due to settlements: | | | |
| Interest rate swaps | 2,851 |
| 2,851 |
| 2,941 |
|
| Forward commodity contracts | (417 | ) | 130 |
| (670 | ) |
| Total other comprehensive income (loss) from hedging | $ | 1,886 |
| $ | 3,964 |
| $ | 2,637 |
|
|
| | | | | | | | | |
| | 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 | ) |
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, 2019, 2018 2017 and 20162017 (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.
|
| | | | | | | | | | |
| | | December 31, 2019 | December 31, 2018 | December 31, 2017 |
| 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 | Fuel, purchased power and cost of natural gas sold | $ | (1,100 | ) | $ | 1,101 |
| $ | (2,207 | ) |
| | | $ | (1,100 | ) | $ | 1,101 |
| $ | (2,207 | ) |
|
| | | | | | | | | | |
| | | 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 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$3.3 million and $12$6.2 million at December 31, 20182019 and 2017,2018, respectively.
(10) FAIR VALUE MEASUREMENTS
Nonrecurring Fair Value Measurement
A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 1.
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.
|
| | | | | | | | | | | | | | | | |
| | As of December 31, 2019 |
| | Level 1 | Level 2 | Level 3 | | Cash Collateral and Counterparty Netting | Total |
| Assets: | | | | | | |
| Commodity derivatives - Utilities | $ | — |
| $ | 1,433 |
| $ | — |
| | $ | (1,085 | ) | $ | 348 |
|
| Total | $ | — |
| $ | 1,433 |
| $ | — |
| | $ | (1,085 | ) | $ | 348 |
|
| | | | | | | |
| Liabilities: | | | | | | |
| Commodity derivatives - Utilities | $ | — |
| $ | 5,254 |
| $ | — |
| | $ | (2,909 | ) | $ | 2,345 |
|
| Total | $ | — |
| $ | 5,254 |
| $ | — |
| | $ | (2,909 | ) | $ | 2,345 |
|
|
| | | | | | | | | | | | | | | | |
| | 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, 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 |
|
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):
|
| | | | | | | |
| | | December 31, |
| | Balance Sheet Location | 2019 | 2018 |
| Derivatives designated as hedges: | | | |
| Asset derivative instruments: | | | |
| Current commodity derivatives | Derivative assets - current | $ | 1 |
| $ | 415 |
|
| Noncurrent commodity derivatives | Other assets, non-current | 3 |
| 18 |
|
| Liability derivative instruments: | | | |
| Current commodity derivatives | Derivative liabilities - current | (490 | ) | (114 | ) |
| Noncurrent commodity derivatives | Other deferred credits and other liabilities | (29 | ) | (4 | ) |
| Total derivatives designated as hedges | $ | (515 | ) | $ | 315 |
|
| | | | |
| Not designated as hedges: | | | |
| Asset derivative instruments: | | | |
| Current commodity derivatives | Derivative assets - current | $ | 341 |
| $ | 1,085 |
|
| Noncurrent commodity derivatives | Other assets, non-current | 2 |
| 1 |
|
| Liability derivative instruments: | | | |
| Current commodity derivatives | Derivative liabilities - current | (1,764 | ) | (833 | ) |
| Noncurrent commodity derivatives | Other deferred credits and other liabilities | (63 | ) | (56 | ) |
| Total derivatives not designated as hedges | $ | (1,484 | ) | $ | 197 |
|
|
| | | | | | | |
| | | 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 | ) |
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, 20182019 and 2017,2018, 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, 20182019 was as follows (in thousands):
| | | Derivative Assets | Gross Amounts of Derivative Assets | Gross Amounts Offset on Consolidated Balance Sheets | Net Amount of Total Derivative Assets on Consolidated Balance Sheets | 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 | ) | $ | — |
| $ | 1,085 |
| $ | (1,085 | ) | $ | — |
|
| Commodity derivative assets not subject to a master netting agreement or similar arrangement | 1,519 |
| — |
| 1,519 |
| 348 |
| — |
| 348 |
|
| Total derivative assets | $ | 2,927 |
| $ | (1,408 | ) | $ | 1,519 |
| $ | 1,433 |
| $ | (1,085 | ) | $ | 348 |
|
| | | Derivative Liabilities | Gross Amounts of Derivative Liabilities | Gross Amounts Offset on Consolidated Balance Sheets | Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets | 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 | ) | $ | — |
| $ | 2,908 |
| $ | (2,908 | ) | $ | — |
|
| Commodity derivative liabilities not subject to a master netting agreement or similar arrangement | 1,007 |
| — |
| 1,007 |
| 2,345 |
| — |
| 2,345 |
|
| Total derivative liabilities | $ | 6,801 |
| $ | (5,794 | ) | $ | 1,007 |
| $ | 5,253 |
| $ | (2,908 | ) | $ | 2,345 |
|
Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 20172018 were as follows (in thousands):
| | | Derivative Assets | Gross Amounts of Derivative Assets | Gross Amounts Offset on Consolidated Balance Sheets | Net Amount of Total Derivative Assets on Consolidated Balance Sheets | 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 | ) | $ | — |
| $ | 1,408 |
| $ | (1,408 | ) | $ | — |
|
| Commodity derivative assets not subject to a master netting agreement or similar arrangement | 304 |
| — |
| 304 |
| 1,519 |
| — |
| 1,519 |
|
| Total derivative assets | $ | 1,586 |
| $ | (1,282 | ) | $ | 304 |
| $ | 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 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 |
|
(11) 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): |
| | | | | | | | | | | | |
| | 2019 | 2018 |
| | Carrying Amount | Fair Value | Carrying Amount | Fair Value |
Cash and cash equivalents (a) | $ | 9,777 |
| $ | 9,777 |
| $ | 20,776 |
| $ | 20,776 |
|
Restricted cash and equivalents (a) | $ | 3,881 |
| $ | 3,881 |
| $ | 3,369 |
| $ | 3,369 |
|
Notes payable (b) | $ | 349,500 |
| $ | 349,500 |
| $ | 185,620 |
| $ | 185,620 |
|
Long-term debt, including current maturities (c) | $ | 3,145,839 |
| $ | 3,479,367 |
| $ | 2,956,578 |
| $ | 3,039,108 |
|
|
| | | | | | | | | | | | |
| | 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. |
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 7.7.
(12) EQUITY
At-the-Market Equity Offering Program
Our ATM equity offering program allows us to sell shares of our common stock with an aggregate value of up 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. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2018 and 2017.
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 CorporationBHC 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 CorporationBHC 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 800,180672,049 shares available to grant at December 31, 2018.2019.
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, 2018,2019, total unrecognized compensation expense related to non-vested stock awards was approximately $12$12 million and is expected to be recognized over a weighted-average period of 1.92 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):
|
| | | | | | | | | |
| | 2018 | 2017 | 2016 |
| Stock-based compensation expense | $ | 12,390 |
| $ | 7,626 |
| $ | 10,885 |
|
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Stock-based compensation expense | $ | 12,095 |
| $ | 12,390 |
| $ | 7,626 |
|
Stock Options
The Company has not issued any stock options since 2014 and has 68,74914,000 stock options outstanding at December 31, 2018.2019. 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, 20182019, was as follows:
|
| | | | | |
| | Restricted Stock | Weighted-Average Grant Date Fair Value |
| | (in thousands) | |
| Balance at beginning of period | 236 |
| $ | 57.50 |
|
| Granted | 92 |
| 73.66 |
|
| Vested | (120 | ) | 56.33 |
|
| Forfeited | (16 | ) | 62.02 |
|
| Balance at end of period | 192 |
| $ | 65.66 |
|
|
| | | | | |
| | 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 |
|
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, waswere as follows:
|
| | | | | | |
| | Weighted-Average Grant Date Fair Value | Total Fair Value of Shares Vested |
| | | (in thousands) |
| 2019 | $ | 73.66 |
| $ | 8,438 |
|
| 2018 | $ | 57.31 |
| $ | 6,776 |
|
| 2017 | $ | 60.63 |
| $ | 7,909 |
|
|
| | | | | | |
| | 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 |
|
As of December 31, 20182019, there was $8.99.0 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$2.9 million at December 31, 20182019 would be reclassified as a liability.
Outstanding performance periods at December 31 were as follows (shares in thousands):
| | | | | Possible Payout Range of Target | | Possible Payout Range of Target |
| Grant Date | Performance Period | Target Grant of Shares | Minimum | Maximum | 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, 2017 - December 31, 2019 | 46 | 0% | 200% |
| January 1, 2018 | January 1, 2018 - December 31, 2020 | 53 | 0% | 200% | January 1, 2018 - December 31, 2020 | 50 | 0% | 200% |
| January 1, 2019 | | January 1, 2019 - December 31, 2021 | 37 | 0% | 200% |
A summary of the status of the Performance Share Plan at December 31 was as follows:
| | | | Equity Portion | Liability Portion | Equity Portion | Liability Portion |
| | | Weighted-Average Grant Date Fair Value (a) | | Weighted-Average Fair Value at | | Weighted-Average Grant Date Fair Value (a) | | Weighted-Average Fair Value at |
| | Shares | December 31, 2018 | Shares | December 31, 2019 |
| | (in thousands) | | (in thousands) | | (in thousands) | | (in thousands) | |
| Performance Shares balance at beginning of period | 74 |
| $ | 55.31 |
| 74 |
| | 77 |
| $ | 57.66 |
| 77 |
| |
| Granted | 28 |
| 61.82 |
| 28 |
| | 20 |
| 68.72 |
| 20 |
| |
| Forfeited | (3 | ) | 58.14 |
| (3 | ) | | (4 | ) | 64.60 |
| (4 | ) | |
| Vested | (22 | ) | 54.92 |
| (22 | ) | | (26 | ) | 47.76 |
| (26 | ) | |
| Performance Shares balance at end of period | 77 |
| $ | 57.66 |
| 77 |
| $ | 76.03 |
| 67 |
| $ | 64.32 |
| 67 |
| $ | 89.63 |
|
_____________________
| |
| (a) | The grant date fair values for the performance shares granted in 2019, 2018 2017 and 20162017 were determined by Monte Carlo simulation using a blended volatility of 21%, 23%21% and 24%23%, 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. |
The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:
| | | | Weighted Average Grant Date Fair Value | Weighted Average Grant Date Fair Value |
| December 31, 2019 | | $ | 68.72 |
|
| December 31, 2018 | $ | 61.82 |
| $ | 61.82 |
|
| December 31, 2017 | $ | 63.52 |
| $ | 63.52 |
|
| December 31, 2016 | $ | 47.76 |
| |
There were no performancePerformance plan payouts during the years ended December 31, 2018, 2017, and 2016.have been as follows (in thousands):
|
| | | | | | | | | |
| Performance Period | Year Paid | Stock Issued | Cash Paid | Total Intrinsic Value |
| January 1, 2016 to December 31, 2018 | 2019 | 44 |
| $ | 2,860 |
| $ | 5,720 |
|
| January 1, 2015 to December 31, 2017 | | — |
| — |
| — |
|
| January 1, 2014 to December 31, 2016 | | — |
| — |
| — |
|
On January 29, 2019,28, 2020, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 20162017 through December 31, 20182019 performance period was at the 74.836.3 percentile of its peer group and confirmed a payout equal to 161.9%58.86% of target shares, valued at $5.7$2.2 million. The payout was fully accrued at December 31, 2018.2019.
As of December 31, 20182019, there was $3.23.4 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.81.6 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, 2018,2019, there were 253,418214,967 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 no0 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. OnIn 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
The accounting for other general corporate purposes.
Aa 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, 2019, 2018 2017 and 20162017 was reduced by $14 million, $14 million, and $10$14 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)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 31:31 (in thousands):
|
| | | | | | | |
| | 2019 | | 2018 |
| Assets | | | |
| Current assets | $ | 13,350 |
| | $ | 13,620 |
|
| Property, plant and equipment of variable interest entities, net | $ | 193,046 |
| | $ | 199,839 |
|
| | | | |
| Liabilities | | | |
| Current liabilities | $ | 6,013 |
| | $ | 5,174 |
|
(13) REGULATORY MATTERS
We had the following regulatory assets and liabilities as of December 31 (in thousands):
|
| | | | | | | |
| | 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 |
|
|
| | | | | | |
| | 2019 | 2018 |
| Regulatory assets | | |
Deferred energy and fuel cost adjustments (a) | $ | 34,088 |
| $ | 29,661 |
|
Deferred gas cost adjustments (a) | 1,540 |
| 3,362 |
|
Gas price derivatives (a) | 3,328 |
| 6,201 |
|
Deferred taxes on AFUDC (b) | 7,790 |
| 7,841 |
|
Employee benefit plans (c) | 115,900 |
| 110,524 |
|
Environmental (a) | 1,454 |
| 959 |
|
Loss on reacquired debt (a) | 24,777 |
| 21,001 |
|
Renewable energy standard adjustment (a) | 1,622 |
| 1,722 |
|
Deferred taxes on flow through accounting (c) | 41,220 |
| 31,044 |
|
Decommissioning costs (a) | 10,670 |
| 11,700 |
|
Gas supply contract termination (a) | 8,485 |
| 14,310 |
|
Other regulatory assets (a) | 20,470 |
| 45,910 |
|
| Total regulatory assets | 271,344 |
| 284,235 |
|
| Less current regulatory assets | (43,282 | ) | (48,776 | ) |
| Regulatory assets, non-current | $ | 228,062 |
| $ | 235,459 |
|
| | | |
| Regulatory liabilities | | |
Deferred energy and gas costs (a) | $ | 17,278 |
| $ | 6,991 |
|
Employee benefit plan costs and related deferred taxes (c) | 43,349 |
| 42,533 |
|
Cost of removal (a) | 166,727 |
| 150,123 |
|
Excess deferred income taxes (c) | 285,438 |
| 310,562 |
|
| TCJA revenue reserve | 3,418 |
| 18,032 |
|
Other regulatory liabilities (c) | 20,442 |
| 12,553 |
|
| Total regulatory liabilities | 536,652 |
| 540,794 |
|
| Less current regulatory liabilities | (33,507 | ) | (29,810 | ) |
| Regulatory liabilities, non-current | $ | 503,145 |
| $ | 510,984 |
|
__________
| |
| (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. |
Regulatory assets represent items we expect to recover from customers through probable future rates.
Deferred Energy and Fuel Cost Adjustments - 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, 2019 are hedged over a maximum forward term of two 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.
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.
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 Liquefied Natural Gas Plant decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing.
Gas Supply Contract Termination - Agreements under the previous ownership 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 Colorado, Nebraska, 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 CPUC, NPSC 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. (13) REGULATORY MATTERS
Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.
TCJA revenue reserve
Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs.
The TCJA signed into law on December 22, 2017, reduced
Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the federal corporatecumulative 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 rate from 35%effect of the adjustment required under accounting for compensation - defined benefit plans, to 21%. Effective January 1, 2018,record 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 currentfull pension and post-retirement benefit obligations. Such income tax expense embedded in those tariffs. Black Hillseffect has been collaboratinggrossed-up to account for the revenue requirement associated with utility commissionsa 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 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.depreciation expense.
A list of states where benefits to customers of federal tax reform have been approved is summarized below.
|
| | | | |
| 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 |
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 - The revaluation 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 ofregulated utilities' deferred tax assets and liabilities in 2017. A majoritydue to the passage of the TCJA was recorded as an excess deferred taxes are subjectincome tax to be refunded to customers primarily using the average rate assumption method,normalization principles as prescribed byin the IRS, and will generallyTCJA.
TCJA Revenue Reserve - Revenue to be amortizedreturned to customers as a reduction of customer rates over the remaining livesresult of the related assets. As of December 31, 2018, the Company has amortized $2.1 million of this regulatory liability. The portion that was eligibleTCJA. See Note 15 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 moreadditional information.
Regulatory Matters
Electric Utilities Regulatory Activity
Corriedale Wind ProjectSouth Dakota Electric
Settlement
On December 17,January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement agreement to extend the 6-year moratorium period by an additional 3 years to June 30, 2026. Also, as part of the settlement, we withdrew our application for deferred accounting treatment and expensed $5.4 million of development costs related to projects we no longer intend to construct. This settlement amends a previous agreement approved by the SDPUC on June 16, 2017, whereby South Dakota Electric would not increase base rates, absent an extraordinary event, for a 6 year moratorium period effective July 1, 2017. The moratorium period also includes suspension of both the TFA and EIA.
FERC Formula Rate
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 combined. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year.
South Dakota Electric and Wyoming Electric
Renewable Ready
In July 2019, South Dakota Electric and Wyoming Electric filed a joint application withreceived approvals for the WPSC for aRenewable Ready program and related jointly-filed CPCN to construct a new $57 million, 40 MWCorriedale. The wind generation project near Cheyenne, Wyoming. If approved, the 40 MW Corriedale Wind Energy Project wouldwill be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric and Wyoming Electric.received approval from the SDPUC to increase the offering under the program by 12.5 MW. 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 to2 electric utilities also received a determination from the WPSC which includedto increase the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subjectproject to an open public process governed by the WPSC.52.5 MW. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process$79 million project is expected to be completedin service by year-end 2019.2020.
Black Hills Wyoming and Wyoming Electric
Wygen 1 FERC Filing
On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for an additional 20 years to December 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.
Wyoming Electric
Blockchain Tariff
On April 30, 2019, the WPSC approved Wyoming Electric’s application for a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne and Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state.
PCA 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 willwas to 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 stipulatesstipulated 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
Rate Review
On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates willwere to generate approximately $12 million of new annual revenue. The APSC’s approval also allowsallowed Arkansas Gas to include $11 million of revenue that is currentlywas being collected through certain rider mechanisms in the new base rates. The new revenue increase iswas 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.
WyomingColorado Gas
Jurisdictional Consolidation and Rate Review
On July 16, 2018, the WPSC reachedFebruary 1, 2019, Colorado Gas filed a bench decision approving our Wyoming Gas (Northwest Wyoming) settlement and stipulationrate review with the OCA. We received the final orderCPUC requesting approval to consolidate rates, tariffs, and services of its 2 existing gas distribution territories. The rate review requested $2.5 million in the third quarter of 2018. The settlement provides for $1.0 million of new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a return on equity of 9.6%,new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a capital structure of 54.0% equityrecommended decision denying the company’s plan to consolidate rate territories and 46.0% debt. New rates, inclusive of customer benefits relatedrecommending a rate decrease. Colorado Gas has filed exceptions to the TCJA, were effective September 1, 2018.ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 and completed in early 2019.
KansasNebraska Gas
Jurisdictional Consolidation and Rate Review
On June 19, 2018, KansasOctober 29, 2019, Nebraska 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 investmentsNPSC to double from approximately $8.0 million to $16 millionmerge its 2 gas distribution companies. Legal consolidation was 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%2020, and a capital structure of 46.63% equityrate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.services.
Nebraska GasSSIR
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.
Wyoming Gas
Jurisdictional Consolidation and Rate Review
On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its 4 existing gas distribution territories. A new, single statewide rate structure will be effective March 1, 2020. New rates are expected to generate $13 million in new revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.
(14) OPERATING LEASES
Lessee
We have entered into lease agreements forfrom third parties certain office and operation center facilities, communication tower sites, landequipment, and equipment. Rentalmaterials storage. Our leases have remaining terms ranging from less than 1 year to 36 years, including options to extend that are reasonably certain to be exercised.
The components of lease expense incurred under these operatingfor the year ended December 31 were as follows (in thousands) :
|
| | | | |
| | Income Statement Location | 2019 |
| Operating lease cost | Operations and maintenance | $ | 1,456 |
|
| Finance lease cost: | | |
| Amortization of right-of-use asset | Depreciation, depletion and amortization | 100 |
|
| Interest on lease liabilities | Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) | 19 |
|
| Total lease cost | | $ | 1,575 |
|
Supplemental balance sheet information related to leases including monthas of December 31 was as follows (in thousands):
|
| | | | |
| | Balance Sheet Location | 2019 |
| Assets: | | |
| Operating lease assets | Other assets, non-current | $ | 4,629 |
|
| Finance lease assets | Other assets, non-current | 465 |
|
| Total lease assets | | $ | 5,094 |
|
| | | |
| Liabilities: | | |
| Current: | | |
| Operating leases | Accrued liabilities | $ | 1,179 |
|
| Finance lease | Accrued liabilities | 109 |
|
| | | |
| Noncurrent: | | |
| Operating leases | Other deferred credits and other liabilities | 3,821 |
|
| Finance lease | Other deferred credits and other liabilities | 364 |
|
| Total lease liabilities | | $ | 5,473 |
|
Supplemental cash flow information related to month leases for the yearsyear ended December 31 was as follows (in thousands):
|
| | | |
| | 2019 |
| Cash paid included in the measurement of lease liabilities: | |
| Operating cash flows from operating leases | $ | 1,263 |
|
| Operating cash flows from finance lease | $ | 19 |
|
| Financing cash flows from finance lease | $ | 93 |
|
| Right-of-use assets obtained in exchange for lease obligations: | |
| Operating leases | $ | 2,801 |
|
| Finance lease | $ | 67 |
|
Weighted average remaining terms and discount rates related to leases as of December 31 were as follows:
|
| | |
| 2019 |
| Weighted average remaining lease term (years): | |
| Operating leases | 8 years |
|
| Finance lease | 4 years |
|
| |
| Weighted average discount rate: | |
| Operating leases | 4.27 | % |
| Finance lease | 4.19 | % |
As of December 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands):
|
| | | | | | | | | |
| | 2018 | 2017 | 2016 |
Rent expense (a) | $ | 2,667 |
| $ | 10,325 |
| $ | 9,568 |
|
|
| | | | | | | | | |
| | Operating Leases | Finance Lease | Total |
| 2020 | 1,018 |
| 126 |
| 1,144 |
|
| 2021 | 865 |
| 126 |
| 991 |
|
| 2022 | 743 |
| 126 |
| 869 |
|
| 2023 | 718 |
| 126 |
| 844 |
|
| 2024 | 714 |
| 10 |
| 724 |
|
| Thereafter | 2,009 |
| — |
| 2,009 |
|
Total lease payments (a) | $ | 6,067 |
| $ | 514 |
| $ | 6,581 |
|
| Less imputed interest | 1,067 |
| 41 |
| 1,108 |
|
| Present value of lease liabilities | $ | 5,000 |
| $ | 473 |
| $ | 5,473 |
|
_______________
| |
| (a) | The decrease in rent expense is primarily driven by current year expiration of office leasesLease payments exclude payments to landlords for common area maintenance, real estate taxes, and by purchases of facilities previously leased.insurance. |
The following is a schedule
As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under the operating lease agreements as of December 31, 2018 were as follows (in thousands):
|
| | | |
| | Operating Leases |
| 2019 | $ | 1,052 |
|
| 2020 | 464 |
|
| 2021 | 344 |
|
| 2022 | 224 |
|
| 2023 | 216 |
|
| Thereafter | 1,776 |
|
Total lease payments | $ | 4,076 |
|
Lessor
We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years.
The components of lease revenue for the year ended December 31 were as follows (in thousands):
|
| | | | |
| | Income Statement Location | 2019 |
| Operating lease income | Revenue | $ | 2,306 |
|
|
| | | |
| 2019 | $ | 1,052 |
|
| 2020 | $ | 464 |
|
| 2021 | $ | 344 |
|
| 2022 | $ | 224 |
|
| 2023 | $ | 216 |
|
| Thereafter | $ | 1,776 |
|
As of December 31, 2019, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands):
|
| | | |
| | Operating Leases |
| 2020 | 2,227 |
|
| 2021 | 1,857 |
|
| 2022 | 1,793 |
|
| 2023 | 1,799 |
|
| 2024 | 1,743 |
|
| Thereafter | 53,739 |
|
| Total lease receivables | $ | 63,158 |
|
(15) 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,federal and state utility commissions, 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, 2018,2019, the Company has amortized $2.1$6.5 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2018,2019, 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):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Current: | | | |
| Federal | $ | (8,578 | ) | $ | 325 |
| $ | (6,193 | ) |
| State | 138 |
| 247 |
| (1,432 | ) |
| | (8,440 | ) | 572 |
| (7,625 | ) |
| Deferred: | | | |
| Federal | 34,551 |
| (25,022 | ) | 76,522 |
|
| State | 3,469 |
| 783 |
| 4,470 |
|
| | 38,020 |
| (24,239 | ) | 80,992 |
|
| | | | |
| | $ | 29,580 |
| $ | (23,667 | ) | $ | 73,367 |
|
|
| | | | | | | | | |
| | 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 |
|
Included in discontinued operations is a tax benefit of $2.6 million $8.4 million and $49$8.4 million for 2018 2017 and 2016,2017, respectively.
The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands):
| | | | 2018 | 2017 | 2019 | 2018 |
| Deferred tax assets: | | |
| Regulatory liabilities | $ | 92,966 |
| $ | 90,742 |
| $ | 89,754 |
| $ | 92,966 |
|
| Employee benefits | 14,039 |
| 18,724 |
| |
| State tax credits | | 23,261 |
| 20,466 |
|
| Federal net operating loss | 139,371 |
| 155,276 |
| 120,624 |
| 139,371 |
|
| State net operating loss | | 13,537 |
| 16,647 |
|
| Partnership | | 14,030 |
| 16,032 |
|
| Credit Carryovers | | 27,139 |
| 23,124 |
|
Other deferred tax assets(a) | 101,579 |
| 74,561 |
| 33,395 |
| 39,349 |
|
| Less: Valuation allowance | (11,809 | ) | (9,121 | ) | (12,063 | ) | (11,809 | ) |
| Total deferred tax assets | 336,146 |
| 330,182 |
| 309,677 |
| 336,146 |
|
| | | |
| Deferred tax liabilities: | | |
| Accelerated depreciation, amortization and other property-related differences | (529,338 | ) | (510,774 | ) | (533,292 | ) | (529,338 | ) |
| Regulatory assets | (32,324 | ) | (26,245 | ) | (23,586 | ) | (32,324 | ) |
Goodwill (b) | (602 | ) | (46,392 | ) | (15,875 | ) | (602 | ) |
| State deferred tax liability | (64,095 | ) | (58,930 | ) | (72,911 | ) | (64,095 | ) |
| Deferred costs | (13,351 | ) | (16,063 | ) | |
| Other deferred tax liabilities | (7,767 | ) | (8,298 | ) | (24,732 | ) | (21,118 | ) |
| Total deferred tax liabilities | (647,477 | ) | (666,702 | ) | (670,396 | ) | (647,477 | ) |
| | | |
| Net deferred tax liability | $ | (311,331 | ) | $ | (336,520 | ) | $ | (360,719 | ) | $ | (311,331 | ) |
_______________
| |
| (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. |
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
| | | | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 |
| Federal statutory rate | 21.0 | % | 35.0 | % | 35.0 | % | 21.0 | % | 21.0 | % | 35.0 | % |
| State income tax (net of federal tax effect) | 2.3 |
| 0.9 |
| 1.2 |
| 1.5 |
| 2.3 |
| 0.9 |
|
| Percentage depletion | (0.4 | ) | (0.6 | ) | (0.8 | ) | |
Non-controlling interest (a) | (1.3 | ) | (1.8 | ) | (1.6 | ) | (1.2 | ) | (1.3 | ) | (1.8 | ) |
| Equity AFUDC | — |
| (0.2 | ) | (0.5 | ) | |
| Tax credits | (2.0 | ) | (1.7 | ) | (0.4 | ) | (3.9 | ) | (2.0 | ) | (1.7 | ) |
| Transaction costs | — |
| — |
| 0.5 |
| |
| Accounting for uncertain tax positions adjustment | — |
| (0.2 | ) | (2.7 | ) | |
Flow-through adjustments (b) | (1.6 | ) | (1.1 | ) | (2.1 | ) | (2.4 | ) | (1.6 | ) | (1.1 | ) |
Jurisdictional simplification project (d) | (28.5 | ) | — |
| — |
| |
Jurisdictional consolidation project (d) | | — |
| (28.5 | ) | — |
|
| Other tax differences | (0.4 | ) | (0.9 | ) | 0.1 |
| (1.6 | ) | (0.1 | ) | (2.6 | ) |
| IRC 172(f) carryback claim | — |
| (0.7 | ) | — |
| |
TCJA corporate rate reduction (c) | 1.6 |
| (2.7 | ) | — |
| — |
| 1.6 |
| (2.7 | ) |
Amortization of excess deferred income tax expense (e) | | (1.2 | ) | (0.7 | ) | — |
|
| | (9.3 | )% | 26.0 | % | 28.7 | % | 12.2 | % | (9.3 | )% | 26.0 | % |
_________________________
| |
| (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$7.6 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. |
| |
| (e) | Primarily TCJA - see above. |
At December 31, 20182019, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands):
|
| | | | | | | | |
| | | Amounts | | Expiration Dates |
| Federal Net Operating Loss Carryforward | | $ | 575,457 |
| | 2022 | to | 2037 |
| | | | | | | |
State Net Operating Loss Carryforward (a) | | $ | 224,716 |
| | 2020 | to | 2040 |
|
| | | | | | | | |
| | | Amounts | | Expiration Dates |
| Federal Net Operating Loss Carryforward | | $ | 663,741 |
| | 2021 | to | 2038 |
| | | | | | | |
| State Net Operating Loss Carryforward | | $ | 542,632 |
| | 2019 | to | 2038 |
| |
| (a) | The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes. |
As of December 31, 20182019, we had a $0.4$0.5 million valuation allowance against the state NOL carryforwards. Our 20182019 analysis of the ability to utilize such NOLs resulted in a $0.4 millionno 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.allowance. 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):
|
| | | |
| | Changes in Uncertain Tax Positions |
| Beginning balance at January 1, 2017 | $ | 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 |
|
| Additions for prior year tax positions | 446 |
|
| Reductions for prior year tax positions | (862 | ) |
| Additions for current year tax positions | 998 |
|
| Settlements | — |
|
| Ending balance at December 31, 2019 | $ | 4,165 |
|
|
| | | |
| | 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 |
|
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.1 million.$0.3 million.
We recognized no0 interest expense associated with income taxes for the years ended December 31, 2018,2019, December 31, 20172018 and December 31, 2016.2017. We had no0 accrued interest (before tax effect) associated with income taxes at December 31, 20182019 and December 31, 2017.2018.
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 filesfiled a separate consolidated tax return from Black Hills CorporationBHC and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. Black Hills CorporationBHC is no longer subject to examination for tax years prior to 2015.2016.
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, 2018,2019, 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, 2019.2020.
State tax credits have been generated and are available to offset future state income taxes. At December 31, 20182019, we had the following state tax credit carryforwards (in thousands):
|
| | | | | | |
| State Tax Credit Carryforwards | Expiration Year |
| ITC | $ | 23,060 |
| 2023 | to | 2041 |
| Research and development | $ | 201 |
| No expiration |
|
| | | | | | |
| State Tax Credit Carryforwards | Expiration Year |
| Investment tax credit | $ | 20,285 |
| 2023 | to | 2036 |
| Research and development | $ | 180 |
| No expiration |
As of December 31, 2018,2019, we had an $11a $9 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.
(16) 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): |
| | | | | | | |
| | Location on the Consolidated Statements of Income | Amount Reclassified from AOCI |
| December 31, 2019 | December 31, 2018 |
| Gains and (losses) on cash flow hedges: | | | |
| Interest rate swaps | Interest expense | $ | (2,851 | ) | $ | (2,851 | ) |
| Commodity contracts | Fuel, purchased power and cost of natural gas sold | 417 |
| (130 | ) |
| | | (2,434 | ) | (2,981 | ) |
| Income tax | Income tax benefit (expense) | 611 |
| 630 |
|
| Total reclassification adjustments related to cash flow hedges, net of tax | | $ | (1,823 | ) | $ | (2,351 | ) |
| | | | |
| Amortization of components of defined benefit plans: | | | |
| Prior service cost | Operations and maintenance | $ | 77 |
| $ | 178 |
|
| | | | |
| Actuarial gain (loss) | Operations and maintenance | (745 | ) | (2,487 | ) |
| | | (668 | ) | (2,309 | ) |
| Income tax | Income tax benefit (expense) | (453 | ) | 543 |
|
| Total reclassification adjustments related to defined benefit plans, net of tax | | $ | (1,121 | ) | $ | (1,766 | ) |
| | | | |
| Total reclassifications | | $ | (2,944 | ) | $ | (4,117 | ) |
|
| | | | | | | |
| | 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 | ) |
Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands):
|
| | | | | | | | | | | | |
| | Derivatives Designated as Cash Flow Hedges | | |
| | Interest Rate Swaps | Commodity Derivatives | Employee Benefit Plans | Total |
| As of December 31, 2018 | $ | (17,307 | ) | $ | 328 |
| $ | (9,937 | ) | $ | (26,916 | ) |
| Other comprehensive income (loss) | | | | |
| before reclassifications | — |
| (422 | ) | (6,261 | ) | (6,683 | ) |
| Amounts reclassified from AOCI | 2,185 |
| (362 | ) | 1,121 |
| 2,944 |
|
| As of December 31, 2019 | $ | (15,122 | ) | $ | (456 | ) | $ | (15,077 | ) | $ | (30,655 | ) |
| | | | | |
| | 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, 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 | ) |
(17) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
|
| | | | | | | | | | | |
| Years ended December 31, | 2019 | | 2018 | | 2017 |
| | (in thousands) |
| Non-cash investing activities and financing from continuing operations - | | | | | |
| Accrued property, plant and equipment purchases at December 31 | $ | 91,491 |
| | $ | 69,017 |
| | $ | 28,191 |
|
| Increase (decrease) in capitalized assets associated with asset retirement obligations | $ | 5,044 |
| | $ | 2,625 |
| | $ | 3,198 |
|
| | | | | | |
| Cash (paid) refunded during the period for continuing operations- | | | | | |
| Interest (net of amounts capitalized) | $ | (131,774 | ) | | $ | (137,965 | ) | | $ | (132,428 | ) |
| Income taxes (paid) refunded | $ | 4,682 |
| | $ | (14,730 | ) | | $ | 1,775 |
|
|
| | | | | | | | | | | |
| 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 | ) |
(18) 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, 2018,2019, 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:
|
| | |
| | 2019 | 2018 |
| Equity | 20% | 17% |
| Real estate | 3 | 4 |
| Fixed income | 71 | 71 |
| Cash | 1 | 3 |
| Hedge funds | 5 | 5 |
| Total | 100% | 100% |
|
| | |
| | 2018 | 2017 |
| Equity | 17% | 26% |
| Real estate | 4 | 4 |
| Fixed income | 71 | 63 |
| Cash | 3 | 1 |
| Hedge funds | 5 | 6 |
| Total | 100% | 100% |
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 PlansPlan
BHC sponsors a retiree healthcare plansplan (Healthcare Plans)Plan) 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 PlansPlan for participating business units are pre-funded via VEBAs.VEBA trusts. 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 PlansPlan on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG Plans provideCorporation Retiree Medical Plan provides for partial pre-funding via VEBAs and a Grantor Trust.VEBA trusts. 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, KansasIowa and Iowa.Kansas. We do not pre-fund the Healthcare PlansPlan for those employees outside Arkansas, KansasIowa and Iowa.Kansas.
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):
|
| | | | | | |
| | 2018 | 2017 |
| Defined Contribution Plan | | |
| Company retirement contribution | $ | 8,766 |
| $ | 10,223 |
|
| Matching contributions | $ | 13,559 |
| $ | 9,811 |
|
|
| | | | | | |
| | 2019 | 2018 |
| Defined Contribution Plan | | |
| Company retirement contributions | $ | 9,714 |
| $ | 8,766 |
|
| Company matching contributions | $ | 14,558 |
| $ | 13,559 |
|
| | | | 2018 | 2017 | 2019 | 2018 |
| Defined Benefit Plans | | |
| Defined Benefit Pension Plan | $ | 12,700 |
| $ | 27,700 |
| $ | 12,700 |
| $ | 12,700 |
|
| Non-Pension Defined Benefit Postretirement Healthcare Plans | $ | 5,298 |
| $ | 4,332 |
| |
| Non-Pension Defined Benefit Postretirement Healthcare Plan | | $ | 7,033 |
| $ | 5,298 |
|
| Supplemental Non-Qualified Defined Benefit Plans | $ | 2,073 |
| $ | 3,217 |
| $ | 2,344 |
| $ | 2,073 |
|
While we do not have required contributions, we expect to make approximately $13 million in contributions to our Pension Plan in 2019.2020.
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):
| | | Pension Plan | December 31, 2018 | December 31, 2019 |
| | Level 1 | | Level 2 | | Level 3 | | Total Investments Measured at Fair Value | | NAV (a) | | Total Investments | 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 |
| $ | — |
| | $ | 60 |
| | $ | — |
| | $ | 60 |
| | $ | — |
| | $ | 60 |
|
| Common Collective Trust - Cash and Cash Equivalents | — |
| | 9,923 |
| | — |
| | 9,923 |
| | — |
| | 9,923 |
| — |
| | 7,054 |
| | — |
| | 7,054 |
| | — |
| | 7,054 |
|
| Common Collective Trust - Equity | — |
| | 67,457 |
| | — |
| | 67,457 |
| | — |
| | 67,457 |
| — |
| | 87,106 |
| | — |
| | 87,106 |
| | — |
| | 87,106 |
|
| Common Collective Trust - Fixed Income | — |
| | 279,148 |
| | — |
| | 279,148 |
| | — |
| | 279,148 |
| — |
| | 306,275 |
| | — |
| | 306,275 |
| | — |
| | 306,275 |
|
| Common Collective Trust - Real Estate | — |
| | 67 |
| | — |
| | 67 |
| | 13,551 |
| | 13,618 |
| — |
| | — |
| | — |
| | — |
| | 14,239 |
| | 14,239 |
|
| Hedge Funds | — |
| | — |
| | — |
| | — |
| | 18,783 |
| | 18,783 |
| — |
| | — |
| | — |
| | — |
| | 19,550 |
| | 19,550 |
|
| Total investments measured at fair value | $ | — |
| | $ | 358,462 |
| | $ | — |
| | $ | 358,462 |
| | $ | 32,334 |
| | $ | 390,796 |
| $ | — |
| | $ | 400,495 |
| | $ | — |
| | $ | 400,495 |
| | $ | 33,789 |
| | $ | 434,284 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 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”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 Plan | December 31, 2019 |
| | Level 1 | | Level 2 | | Level 3 | | Total Investments Measured at Fair Value | | Total Investments |
| Cash and Cash Equivalents | $ | 8,305 |
| | $ | — |
| | $ | — |
| | $ | 8,305 |
| | $ | 8,305 |
|
| Total investments measured at fair value | $ | 8,305 |
| | $ | — |
| | $ | — |
| | $ | 8,305 |
| | $ | 8,305 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Non-pension Defined Benefit Postretirement Healthcare Plan | December 31, 2018 |
| | Level 1 | | Level 2 | | Level 3 | | Total Investments Measured at Fair Value | | 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. |
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. TheSome of 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.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-day30-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.
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 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.
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
|
| | | | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plan |
| As of December 31 (in thousands), | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| Change in benefit obligation: | | | | | | | | |
| Projected benefit obligation at beginning of year | $ | 445,381 |
| $ | 474,725 |
| | $ | 43,010 |
| $ | 45,112 |
| | $ | 60,817 |
| $ | 69,339 |
|
| Service cost | 5,383 |
| 6,834 |
| | 4,995 |
| 1,764 |
| | 1,815 |
| 2,291 |
|
| Interest cost | 17,374 |
| 15,470 |
| | 1,295 |
| 1,170 |
| | 2,247 |
| 2,085 |
|
| Actuarial (gain) loss | 56,384 |
| (31,340 | ) | | 7,132 |
| (2,963 | ) | | 5,976 |
| (9,045 | ) |
| Benefits paid | (39,146 | ) | (20,308 | ) | | (2,344 | ) | (2,073 | ) | | (7,033 | ) | (5,298 | ) |
| Plan participants’ contributions | — |
| — |
| | — |
| — |
| | 1,455 |
| 1,445 |
|
| Projected benefit obligation at end of year | $ | 485,376 |
| $ | 445,381 |
| | $ | 54,088 |
| $ | 43,010 |
| | $ | 65,277 |
| $ | 60,817 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
Employee Benefit Plan Assets
| | | | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plans (a) | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plan (a) |
| As of December 31 (in thousands), | 2018 | 2017 | | 2018 | 2017 | | 2018 | 2017 | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| Change in fair value of plan assets: | | | | | | | | | | |
| Beginning fair value of plan assets | $ | 416,343 |
| $ | 364,695 |
| | $ | — |
| $ | — |
| | $ | 8,621 |
| $ | 8,470 |
| $ | 390,796 |
| $ | 416,343 |
| | $ | — |
| $ | — |
| | $ | 8,162 |
| $ | 8,621 |
|
| Investment income (loss) | (17,939 | ) | 48,617 |
| | — |
| — |
| | (149 | ) | 120 |
| 69,934 |
| (17,939 | ) | | — |
| — |
| | 260 |
| (149 | ) |
| Employer contributions | 12,700 |
| 27,700 |
| | 2,073 |
| 3,217 |
| | 3,543 |
| 3,025 |
| 12,700 |
| 12,700 |
| | 2,344 |
| 2,073 |
| | 5,461 |
| 3,543 |
|
| Retiree contributions | — |
| — |
| | — |
| — |
| | 1,445 |
| 1,338 |
| — |
| — |
| | — |
| — |
| | 1,455 |
| 1,445 |
|
| Benefits paid | (20,308 | ) | (24,669 | ) | | (2,073 | ) | (3,217 | ) | | (5,298 | ) | (4,332 | ) | (39,146 | ) | (20,308 | ) | | (2,344 | ) | (2,073 | ) | | (7,033 | ) | (5,298 | ) |
| Ending fair value of plan assets | $ | 390,796 |
| $ | 416,343 |
| | $ | — |
| $ | — |
| | $ | 8,162 |
| $ | 8,621 |
| $ | 434,284 |
| $ | 390,796 |
| | $ | — |
| $ | — |
| | $ | 8,305 |
| $ | 8,162 |
|
____________________
| |
| (a) | Assets of VEBAs and Grantor Trust.VEBA trusts. |
The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands):
|
| | | | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| Regulatory assets | $ | 88,471 |
| $ | 82,919 |
| | $ | — |
| $ | — |
| | $ | 11,670 |
| $ | 6,655 |
|
| Current liabilities | $ | — |
| $ | — |
| | $ | 1,420 |
| $ | 1,463 |
| | $ | 4,802 |
| $ | 3,885 |
|
| Non-current assets | $ | — |
| $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| $ | 249 |
|
| Non-current liabilities | $ | 51,093 |
| $ | 54,585 |
| | $ | 51,243 |
| $ | 41,547 |
| | $ | 52,136 |
| $ | 49,015 |
|
| Regulatory liabilities | $ | 3,524 |
| $ | 4,620 |
| | $ | — |
| $ | — |
| | $ | 4,088 |
| $ | 5,207 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
Accumulated Benefit Obligation
|
| | | | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| As of December 31 (in thousands) | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| Accumulated Benefit Obligation | $ | 470,615 |
| $ | 428,851 |
| | $ | 49,241 |
| $ | 40,530 |
| | $ | 65,277 |
| $ | 60,817 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
Components of Net Periodic Expense
Net periodic expense consisted of the following for the year ended December 31 (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 |
| Service cost | $ | 5,383 |
| $ | 6,834 |
| $ | 7,034 |
| | $ | 4,995 |
| $ | 1,764 |
| $ | 1,546 |
| | $ | 1,815 |
| $ | 2,291 |
| $ | 2,300 |
|
| Interest cost | 17,374 |
| 15,470 |
| 15,520 |
| | 1,295 |
| 1,170 |
| 1,276 |
| | 2,247 |
| 2,085 |
| 2,141 |
|
| Expected return on assets | (24,401 | ) | (24,741 | ) | (24,517 | ) | | — |
| — |
| — |
| | (230 | ) | (315 | ) | (315 | ) |
| Net amortization of prior service cost | 26 |
| 58 |
| 58 |
| | 2 |
| 2 |
| 2 |
| | (398 | ) | (398 | ) | (411 | ) |
| Recognized net actuarial loss (gain) | 3,763 |
| 8,632 |
| 4,007 |
| | 535 |
| 1,000 |
| 1,001 |
| | — |
| 216 |
| 499 |
|
| Net periodic expense | $ | 2,145 |
| $ | 6,253 |
| $ | 2,102 |
| | $ | 6,827 |
| $ | 3,936 |
| $ | 3,825 |
| | $ | 3,434 |
| $ | 3,879 |
| $ | 4,214 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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. |
For the yearyears ended December 31, 2019 and 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 yearsyear ended December 31, 2017, and 2016, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’non-service costs were not considered material for the year ended December 31, 2017, 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):
|
| | | | | | | | | | | | | | | | | | | | |
| | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | Non-pension Defined Benefit Postretirement Healthcare Plan |
| | 2019 | 2018 | | 2019 | 2018 | | 2019 | 2018 |
| Net (gain) loss | $ | 5,322 |
| $ | 11,967 |
| | $ | 9,893 |
| $ | 4,668 |
| | $ | 90 |
| $ | 860 |
|
| Prior service cost (gain) | — |
| 1 |
| | 2 |
| 3 |
| | (230 | ) | (317 | ) |
| Reclassification of certain tax effects from AOCI | — |
| (594 | ) | | — |
| (87 | ) | | — |
| (45 | ) |
| Reclassification to regulatory asset | — |
| (5,600 | ) | | — |
| — |
| | — |
| (919 | ) |
| Total AOCI | $ | 5,322 |
| $ | 5,774 |
| | $ | 9,895 |
| $ | 4,584 |
| | $ | (140 | ) | $ | (421 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| | 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 |
|
Assumptions
| | | | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plans | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plan |
| Weighted-average assumptions used to determine benefit obligations: | 2018 | 2017 | 2016 | | 2018 | 2017 | 2016 | | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 |
| | | | | | | | | | | |
| Discount rate | 4.40 | % | 3.71 | % | 4.27 | % | | 4.34 | % | 3.56 | % | 4.02 | % | | 4.28 | % | 3.60 | % | 3.96 | % | 3.27 | % | 4.40 | % | 3.71 | % | | 3.14 | % | 4.34 | % | 3.56 | % | | 3.15 | % | 4.28 | % | 3.60 | % |
| Rate of increase in compensation levels | 3.52 | % | 3.43 | % | 3.47 | % | | 5.00 | % | 5.00 | % | 5.00 | % | | N/A |
| N/A |
| N/A |
| 3.49 | % | 3.52 | % | 3.43 | % | | 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 | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plan |
| Weighted-average assumptions used to determine net periodic benefit cost for plan year: | 2018 | 2017 | 2016 | | 2018 | 2017 | 2016 | | 2018 | 2017 | 2016 | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 | | 2019 | 2018 | 2017 |
| | | | | | | | | | | |
Discount rate (a) | 3.71 | % | 4.27 | % | 4.50 | % | | 3.67 | % | 4.02 | % | 4.28 | % | | 3.60 | % | 4.05 | % | 4.18 | % | 4.40 | % | 3.71 | % | 4.27 | % | | 4.34 | % | 3.67 | % | 4.02 | % | | 4.28 | % | 3.60 | % | 4.05 | % |
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 | % | 6.00 | % | 6.25 | % | 6.75 | % | | N/A |
| N/A |
| N/A |
| | 3.00 | % | 3.93 | % | 3.88 | % |
| Rate of increase in compensation levels | 3.43 | % | 3.47 | % | 3.42 | % | | 5.00 | % | 5.00 | % | 5.00 | % | | N/A |
| N/A |
| N/A |
| 3.52 | % | 3.43 | % | 3.47 | % | | 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%3.27% for the calculation of the 20192020 net periodic pension costs. |
| |
| (b) | The expected rate of return on plan assets is 6.00%5.25% for the calculation of the 20192020 net periodic pension cost. |
The healthcare benefit obligation was determined at December 31 as follows:
|
| | |
| | 2019 | 2018 |
| Trend Rate - Medical | | |
| Pre-65 for next year - All Plans | 6.40% | 6.70% |
| Pre-65 Ultimate trend rate - Black Hills Corp | 4.50% | 4.50% |
| Trend Year | 2027 | 2027 |
| | | |
| Post-65 for next year - All Plans | 4.92% | 4.94% |
| Post-65 Ultimate trend rate - Black Hills Corp | 4.50% | 4.50% |
| Trend Year | 2028 | 2026 |
|
| | |
| | 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 |
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 to employees, which reflect future service, are expected to be paid (in thousands):
|
| | | | | | | | | | | |
| | Defined Benefit Pension Plan | | Supplemental Non-qualified Defined Benefit Plans | | Non-pension Defined Benefit Postretirement Healthcare Plan |
| 2020 | $ | 24,586 |
| | $ | 1,420 |
| | $ | 5,919 |
|
| 2021 | $ | 25,774 |
| | $ | 1,786 |
| | $ | 5,974 |
|
| 2022 | $ | 26,728 |
| | $ | 2,167 |
| | $ | 5,790 |
|
| 2023 | $ | 27,795 |
| | $ | 2,223 |
| | $ | 5,521 |
|
| 2024 | $ | 28,547 |
| | $ | 2,412 |
| | $ | 5,329 |
|
| 2025-2029 | $ | 145,426 |
| | $ | 14,689 |
| | $ | 23,030 |
|
|
| | | | | | | | | | | |
| | 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 |
|
(19) 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:
| |
| • | Colorado Electric’s PPA with PRPA to purchase up to 60 MW of wind energy upon construction of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030. |
Colorado Electric’s PPA with PRPA to purchase 25 MW of unit contingent energy. This agreement will expire June 30, 2024.
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.
South Dakota Electric’s PPA with PRPA to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.
Wyoming Electric’s PPA with Happy Jack, expiring September 3, 2028, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric.
Wyoming Electric’s PPA with Silver Sage, 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.
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.
Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands):
|
| | | | | | | | | |
| | 2019 | 2018 | 2017 |
| Colorado Electric PPA with PRPA - Unit Contingent Energy | $ | 1,802 |
| $ | — |
| $ | — |
|
Colorado Electric PPA Busch Ranch I (a) | $ | — |
| $ | — |
| $ | 1,966 |
|
| South Dakota Electric PPA with PacifiCorp | $ | 7,477 |
| $ | 13,681 |
| $ | 13,218 |
|
| South Dakota Electric Transmission services agreement with PacifiCorp | $ | 1,741 |
| $ | 1,742 |
| $ | 1,671 |
|
| South Dakota Electric PPA with PRPA | $ | 688 |
| $ | 223 |
| $ | — |
|
| Wyoming Electric PPA with Happy Jack | $ | 3,936 |
| $ | 3,884 |
| $ | 3,846 |
|
| Wyoming Electric PPA with Silver Sage | $ | 5,366 |
| $ | 5,376 |
| $ | 4,934 |
|
|
| | | | | | | | | |
| | 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.I. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm. |
| |
(b) | PPAs with Cargill expired on December 31, 2016. |
Power Purchase AgreementAgreements - Related Party
On November 26, 2019, Black Hills Electric Generation completed and placed in service Busch Ranch II. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric under a new PPA, which expires in November 2044.
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.I. Black Hills Electric Generation will provideprovides 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, expiringwhich expires in October 2037.
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. Effective January 1, 2019, we changed how we account for this PPA at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information.
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, 2018,2019, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus):
|
| | |
| | NNG-Ventura | NWPL-Wyoming |
| 2020 | 3,660,000 | 1,520,000 |
| 2021 | 3,650,000 | 1,510,000 |
| 2022 | 1,810,000 | 1,510,000 |
| 2023 | 0 | 1,510,000 |
| 2024 | 0 | 910,000 |
| Thereafter | 0 | 0 |
|
| | | | |
| | 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 |
Purchases under these contracts totaled $6.7 million, $27 million and $65 million for 2019, 2018 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):
|
| | | | | | |
| | Power purchase and transmission services agreements | Natural gas transportation and storage agreements |
| 2020 | $ | 25,476 |
| $ | 156,297 |
|
| 2021 | $ | 11,678 |
| $ | 148,149 |
|
| 2022 | $ | 11,678 |
| $ | 122,340 |
|
| 2023 | $ | 11,678 |
| $ | 93,905 |
|
| 2024 | $ | 2,738 |
| $ | 51,360 |
|
| Thereafter | $ | — |
| $ | 126,147 |
|
|
| | | | | | |
| | 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 |
|
Future Purchase Agreement - Related Party
Wyoming Electric’sElectric has a PPA forwith Black Hills Wyoming expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiringfacility. On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022, includes an option for2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric to purchase Black Hills Wyoming’s ownership in thefrom its 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 IIIpower 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 subject2023, and continuing for an additional 20 years to WPSCDecember 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and FERC approval in order to obtain regulatory treatment.awaits a decision from FERC.
Power Sales Agreements
Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties:
| |
| • | 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, South Dakota Electric will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023. |
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 serveprovide 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, weSouth Dakota Electric 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 expiresis renewed annually on September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.
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 PPA with MEAN expiring contract that expires May 31, 2028.2028. The contract terms are from June 1 through May 31 for each interval listed below. 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. Theour Neil Simpson II and Wygen III plants, with decreasing capacity purchase requirements decreasepurchased over the term of the agreement.
The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: |
| | | | | | | | | | | |
| Contract Years | Total Contract Capacity | | Contingent Capacity Amounts on Wygen III | | Contingent Capacity Amounts on Neil Simpson II |
| 2019-2020 | 15 |
| MW | | 10 |
| MW | | 5 |
| MW |
| 2020-2022 | 15 |
| MW | | 7 |
| MW | | 8 |
| MW |
| 2022-2023 | 15 |
| MW | | 8 |
| MW | | 7 |
| MW |
| 2023-2028 | 10 |
| MW | | 5 |
| MW | | 5 |
| MW |
South Dakota Electric has an agreement throughthat expires December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.
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 itsour land leaseleases for Busch Ranch I, Colorado Electric isour wind generation facilities, we are required to reclaim all land where it haswe have placed wind turbines. The reclamation liability isliabilities are 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,In 2008, 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$1.5 million regulatory asset for manufactured gas processing sites; see Note 1.13 for additional information.
As of December 31, 2018,2019, our estimated liabilities for Iowa’s MGPmanufactured gas processing site currently range from approximately $2.6 million to $6.1$10 million for which we had $2.6 million accrued for remediation of the site as of December 31, 20182019 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.
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.
(20) GUARANTEES
(20) 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):
| | | | Maximum Exposure at | | Maximum Exposure at | |
| Nature of Guarantee | December 31, 2018 | Expiration | December 31, 2019 | Expiration |
Indemnification for subsidiary reclamation/surety bonds (a) | $ | 54,683 |
| Ongoing | $ | 55,527 |
| Ongoing |
Contract performance guarantee (b) | 39,807 |
| December 2019 | 46,831 |
| May 2020 |
| | $ | 94,490 |
| | $ | 102,358 |
| |
_______________________
| |
| (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.II. 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. |
(21) DISCONTINUED OPERATIONS
Results of operations for discontinued operations have beenwere 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 beenwere 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 andWe completed the exit of the Oil and Gas business.divestiture in 2018.
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-taxa pre-tax write down of $13$20 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.
|
| | | |
| | 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 |
|
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.assets.
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): |
| | | | | | |
| | For the Years Ended |
| | December 31, 2018 | December 31, 2017 |
| | | |
| Revenue | $ | 5,897 |
| $ | 25,382 |
|
| | | |
| Operations and maintenance | 11,014 |
| 22,872 |
|
| Loss on sale of assets | 3,259 |
| — |
|
| Depreciation, depletion and amortization | 1,300 |
| 7,521 |
|
| Impairment of long-lived assets | — |
| 20,385 |
|
| Total operating expenses | 15,573 |
| 50,778 |
|
| | | |
| Operating (loss) | (9,676 | ) | (25,396 | ) |
| | | |
| Interest income (expense), net | (19 | ) | 181 |
|
| Other income (expense), net | 190 |
| (297 | ) |
| Income tax benefit | 2,618 |
| 8,413 |
|
| | | |
| Net (loss) from discontinued operations | $ | (6,887 | ) | $ | (17,099 | ) |
|
| | | | | | | | | |
| | 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 | ) |
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.
(22) 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):
|
| | | |
| | 2016 |
| Acquisition of properties: | |
| Proved | $ | — |
|
| Unproved | 910 |
|
| Exploration costs | 1,102 |
|
| Development costs | 4,657 |
|
| Asset retirement obligations incurred | — |
|
| Total costs incurred | $ | 6,669 |
|
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.
|
| | | | | | | | | |
| | 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. |
Capitalized Costs
Following is information concerning capitalized costs for the years ended December 31 (in thousands):
|
| | | |
| | 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 |
|
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):
|
| | | |
| | 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 | ) |
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):
|
| | | |
| | 2016 |
| Leasehold acquisition cost | $ | 963 |
|
| Exploration cost | 532 |
|
| Capitalized interest | 50 |
|
| Total | $ | 1,545 |
|
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):
|
| | | |
| | 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 |
|
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):
|
| | | |
| | 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 |
|
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.
(23) 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 20182019 and 2017.2018.
|
| | | | | | | | | | | | |
| | 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) |
| 2019 | | | | |
| Revenue | $ | 597,810 |
| $ | 333,888 |
| $ | 325,548 |
| $ | 477,654 |
|
| Operating income | $ | 160,131 |
| $ | 54,001 |
| $ | 70,551 |
| $ | 121,359 |
|
| Income from continuing operations | $ | 107,362 |
| $ | 17,693 |
| $ | 15,395 |
| $ | 72,872 |
|
| (Loss) from discontinued operations | $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Net income attributable to noncontrolling interest | $ | (3,554 | ) | $ | (3,110 | ) | $ | (3,655 | ) | $ | (3,693 | ) |
| Net income available for common stock | $ | 103,808 |
| $ | 14,583 |
| $ | 11,740 |
| $ | 69,179 |
|
| | | | | |
| Amounts attributable to common shareholders: | | | | |
| Net income from continuing operations | $ | 103,808 |
| $ | 14,583 |
| $ | 11,740 |
| $ | 69,179 |
|
| Net (loss) from discontinued operations | — |
| — |
| — |
| — |
|
| Net income available for common stock | $ | 103,808 |
| $ | 14,583 |
| $ | 11,740 |
| $ | 69,179 |
|
| | | | | |
| Income per share for continuing operations - Basic | $ | 1.73 |
| $ | 0.24 |
| $ | 0.19 |
| $ | 1.13 |
|
| (Loss) per share for discontinued operations - Basic | — |
| — |
| — |
| — |
|
| Earnings per share - Basic | $ | 1.73 |
| $ | 0.24 |
| $ | 0.19 |
| $ | 1.13 |
|
| | | | | |
| Income per share for continuing operations - Diluted | $ | 1.73 |
| $ | 0.24 |
| $ | 0.19 |
| $ | 1.13 |
|
| (Loss) per share for discontinued operations - Diluted | — |
| — |
| — |
| — |
|
| Earnings per share - Diluted | $ | 1.73 |
| $ | 0.24 |
| $ | 0.19 |
| $ | 1.13 |
|
Included within the Income (loss) from continuing operations in the third quarter of 2019 is $15 million non-cash after-tax impairment of our investment in equity securities of a privately held oil and gas company.
|
| | | | | | | | | | | | |
| | 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 | $ | 148,274 |
| $ | 69,551 |
| $ | 65,085 |
| $ | 114,127 |
|
| Income from continuing operations | $ | 138,977 |
| $ | 27,167 |
| $ | 21,801 |
| $ | 91,604 |
|
| (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 available for common stock | $ | 133,004 |
| $ | 21,917 |
| $ | 16,950 |
| $ | 86,571 |
|
| | | | | |
| Amounts attributable to common shareholders: | | | | |
| Net income from continuing operations | $ | 135,347 |
| $ | 24,344 |
| $ | 17,807 |
| $ | 87,831 |
|
| Net (loss) from discontinued operations | (2,343 | ) | (2,427 | ) | (857 | ) | (1,260 | ) |
| Net income available for common stock | $ | 133,004 |
| $ | 21,917 |
| $ | 16,950 |
| $ | 86,571 |
|
| | | | | |
| Income per share for continuing operations - Basic | $ | 2.54 |
| $ | 0.46 |
| $ | 0.33 |
| $ | 1.52 |
|
| (Loss) per share for discontinued operations - Basic | (0.05 | ) | (0.05 | ) | (0.02 | ) | (0.02 | ) |
| Earnings per share - Basic | $ | 2.49 |
| $ | 0.41 |
| $ | 0.32 |
| $ | 1.50 |
|
| | | | | |
| Income per share for continuing operations - Diluted | $ | 2.50 |
| $ | 0.45 |
| $ | 0.32 |
| $ | 1.51 |
|
| (Loss) per share for discontinued operations - Diluted | (0.04 | ) | (0.05 | ) | (0.02 | ) | (0.02 | ) |
| Earnings per share - Diluted | $ | 2.46 |
| $ | 0.40 |
| $ | 0.31 |
| $ | 1.49 |
|
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.
|
| | | | | | | | | | | | |
| | 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 |
|
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.
| |
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| |
| ITEM 9A. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 20182019. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2018,2019, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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Management’s Report on Internal Control over Financial Reporting is presented on Page 8673 of this Annual Report on Form 10-K. |
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| ITEM 9B. | OTHER INFORMATION |
None.
PART III
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| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 20192020 Annual Meeting of Shareholders, which is incorporated herein by reference.
Information about our Executive Officers
is reported in Part 1 of this Annual Report on Form 10-K.
David R. Emery, age 56, has been Executive Chairman since January 1, 2019, Chairman and Chief Executive Officer from 2016 through 2018, and Chairman, President and Chief Executive Officer from 2005 through 2015. Prior to that, he held various positions with the Company, including President and Chief Executive Officer and member of the Board of Directors from 2004 to 2005, President and Chief Operating Officer — Retail Business Segment from 2003 to 2004 and Vice President — Fuel Resources from 1997 to 2003. Mr. Emery has 29 years of experience with the Company.
Linden R. Evans, age 56, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer — Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 17 years of experience with the Company.
Scott A. Buchholz, age 57, has been our Senior Vice President — Chief Information Officer since the closing of the Aquila Transaction in 2008. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 38 years of experience with the Company, including 28 years with Aquila.
Brian G. Iverson, age 56, has been Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary since February 1, 2019. He served as Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 15 years of experience with the Company.
Richard W. Kinzley, age 53, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 19 years of experience with the Company.
Jennifer C. Landis, age 44, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 17 years of experience with the Company.
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| ITEM 11. | EXECUTIVE COMPENSATION |
Information required under this item is set forth in the Proxy Statement for our 20192020 Annual Meeting of Shareholders, which is incorporated herein by reference.
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| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 20192020 Annual Meeting of Shareholders, which is incorporated herein by reference.
EQUITY COMPENSATION PLAN INFORMATION
The following table includes information as of December 31, 20182019 with respect to our equity compensation plans. These plans include the 2005 Omnibus Incentive Plan and 2015 Omnibus Incentive Plan.
| | 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)) | 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) | (a) | (b) | (c) |
| Equity compensation plans approved by security holders | 256,111 |
| (1) | | $ | 41.63 |
| (1) | 800,180 |
| (2) | 160,179 |
| (1) | | $ | 39.99 |
| (1) | 672,049 |
| (2) |
| Equity compensation plans not approved by security holders | — |
| | $ | — |
| | — |
| | — |
| | $ | — |
| | — |
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| Total | 256,111 |
| | $ | 41.63 |
| | 800,180 |
| | 160,179 |
| | $ | 39.99 |
| | 672,049 |
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| (1) | Includes 187,362146,179 full value awards outstanding as of December 31, 20182019, 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, 235,748192,120 shares of unvested restricted stock were outstanding as of December 31, 2018,2019, which are not included in the above table because they have already been issued. |
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| (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. |
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| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 20192020 Annual Meeting of Shareholders, which is incorporated herein by reference.
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| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Information regarding principal accounting fees and services is set forth in the Proxy Statement for our 20192020 Annual Meeting to Shareholders, which is incorporated herein by reference.
PART IV
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| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
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| (a) | 1. | Consolidated Financial Statements |
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| | | Financial statements required under this item are included in Item 8 of Part II |
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| | 2. | Schedules |
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| | | Schedule II — Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2019, 2018 2017 and 20162017 |
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| | 3. | Exhibits |
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| | | 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. |
SCHEDULE II
Consolidated valuation and qualifying accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
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| Exhibit Number | Description |
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| 2.1* | |
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| 2.2* | |
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| 2.3* | |
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| 3.1* | |
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| 3.2* | |
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| 4.1* | |
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| 4.2* | |
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| 4.3* | |
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| 4.4* | |
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| 4.5 | |
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| 10.1*† | |
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| 10.2*† | |
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| 10.3*† | |
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| 10.4*† | |
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10.5†10.5*† | |
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10.6†10.6*† | |
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| 10.7*† | |
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| 10.8*† | |
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| 10.9*† | |
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| 10.10*† | |
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| 10.11*† | |
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10.12*†10.12† | |
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| 10.13*† | |
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| 10.14*† | |
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10.15*†10.15† | |
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10.16*†10.16† | |
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| 10.17*† | |
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10.18†10.18*† | |
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| 10.19*† | |
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| 10.22* | Amended and Restated Credit Agreement dated as of July 30, 2018 (relating to $300 million, two-year term loan), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on July 31, 2018). |
| First Amendment dated as of June 17, 2019 to Amended and Restated Credit Agreement dated as of July 30, 2018, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8–K filed on June 17, 2019). |
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| 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). |
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| 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). |
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| 21 | |
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| 23.1 | |
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23.2 | |
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| 31.1 | |
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| 31.2 | |
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| 32.1 | |
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| 32.2 | |
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| 95 | |
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101101.INS | Financial StatementsXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL Formattags are embedded within the Inline XBRL document |
| 101.SCH | XBRL Taxonomy Extension Schema Document |
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
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| 104 | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) |
________________________
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| * | Previously filed as part of the filing indicated and incorporated by reference herein. |
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| † | Indicates a board of director or management compensatory plan. |
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| ITEM 16. | FORM 10-K SUMMARY |
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | | BLACK HILLS CORPORATION |
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| | | By: | /S/ LINDEN R. EVANS |
| | | Linden R. Evans, President and Chief Executive Officer |
| Dated: | February 19, 201914, 2020 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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| /S/ LINDEN R. EVANS | Director and | February 19, 201914, 2020 |
| Linden R. Evans, President | Principal Executive Officer | |
| and Chief Executive Officer | | |
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| /S/ RICHARD W. KINZLEY | Principal Financial and | February 19, 201914, 2020 |
| Richard W. Kinzley, Senior Vice President | Accounting Officer | |
| and Chief Financial Officer | | |
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| /S/ DAVID R. EMERY | Director and | February 19, 201914, 2020 |
| David R. Emery, Executive Chairman | Executive Chairman | |
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| /S/ TONY A. JENSEN | Director | February 14, 2020 |
| Tony A. Jensen | | |
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| /S/ MICHAEL H. MADISON | Director | February 19, 201914, 2020 |
| Michael H. Madison | | |
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| /S/ KATHLEEN S. MCALLISTER | Director | February 14, 2020 |
| Kathleen S. McAllister | | |
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| /S/ STEVEN R. MILLS | Director | February 19, 201914, 2020 |
| Steven R. Mills | | |
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| /S/ ROBERT P. OTTO | Director | February 19, 201914, 2020 |
| Robert P. Otto | | |
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| /S/ REBECCA B. ROBERTS | Director | February 19, 201914, 2020 |
| Rebecca B. Roberts | | |
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| /S/ MARK A. SCHOBER | Director | February 19, 201914, 2020 |
| Mark A. Schober | | |
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| /S/ TERESA A. TAYLOR | Director | February 19, 201914, 2020 |
| Teresa A. Taylor | | |
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| /S/ JOHN B. VERING | Director | February 19, 201914, 2020 |
| John B. Vering | | |
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| /S/ THOMAS J. ZELLER | Director | February 19, 201914, 2020 |
| Thomas J. Zeller | | |
