bkh-20201231
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
Or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission File Number 001-31303
BLACK HILLS CORPORATION
Incorporated in South Dakota IRS Identification Number 46-0458824
7001 Mount Rushmore Road
Rapid City, South Dakota57702
Registrant’s telephone number (605) 721-1700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol 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 is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
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 ☒
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 ☐
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 ☐
Indicate by check mark whether the registrant 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.
Large accelerated filer ☒ Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the Registrant 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. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
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, 2020, was $3,528,768,075
Class Outstanding at January 31, 2021
Documents Incorporated by Reference
Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2021 Annual Meeting of Stockholders to be held on April 27, 2021, are incorporated by reference in Part III of this Form 10-K.
TABLE OF CONTENTS
Page
GLOSSARY OF TERMS AND ABBREVIATIONS 4
WEBSITE ACCESS TO REPORTS 9
FORWARD-LOOKING INFORMATION 9
Part I
ITEMS 1. and 2. BUSINESS AND PROPERTIES 10
History and Organization 10
Electric Utilities 10
Gas Utilities 14
Utility Regulation Characteristics 17
Power Generation 18
Environmental Matters 21
Other Properties 22
Human Capital Resources 22
ITEM 1A. RISK FACTORS 24
ITEM 1B. UNRESOLVED STAFF COMMENTS 31
ITEM 3. LEGAL PROCEEDINGS 31
ITEM 4. MINE SAFETY DISCLOSURES 31
INFORMATION ABOUT OUR EXECUTIVE OFFICERS 32
Part II
ITEM 6. SELECTED FINANCIAL DATA 33
Executive Summary 34
Key Elements of our Business Strategy 34
Prospective Information 37
Company Highlights 37
Results of Operations - Consolidated Summary and Overview 41
Non-GAAP Financial Measure 42
Electric Utilities 43
Gas Utilities 46
Power Generation 48
Corporate and Other 49
Liquidity and Capital Resources 50
Cash Flow Activities 51
Capital Sources 52
Credit Ratings 54
Capital Requirements 55
Critical Accounting Policies Involving Significant Estimates 56
New Accounting Pronouncements 59
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 60
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 62
Management’s Report on Internal Controls Over Financial Reporting 62
Reports of Independent Registered Public Accounting Firm 63
Consolidated Statements of Income 66
Consolidated Statements of Comprehensive Income 67
Consolidated Balance Sheets 68
Consolidated Statements of Cash Flows 70
Consolidated Statements of Equity 71
Notes to Consolidated Financial Statements 72
Note 1. Business Description and Significant Accounting Policies 72
Note 2. Regulatory Matters 81
Note 3. Commitments, Contingencies and Guarantees 85
Note 4. Revenue 89
Note 5. Property, Plant and Equipment 92
Note 6. Jointly Owned Facilities 93
Note 7. Asset Retirement Obligations 95
Note 8. Leases 95
Note 9. Debt and Credit Facilities 97
Note 10. Stockholders’ Equity 100
Note 11. Risk Management and Derivatives 101
Note 12. Fair Value Measurements 100
Note 13. Other Comprehensive Income 106
Note 14. Variable Interest Entity 104
Note 15. Employee Benefit Plans 108
Note 16. Share-based Compensation Plans 114
Note 18. Business Segment Information 121
Note 19. Subsequent Event 124
ITEM 9A. CONTROLS AND PROCEDURES 125
ITEM 9B. OTHER INFORMATION 125
Part III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 126
ITEM 11. EXECUTIVE COMPENSATION 126
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 126
Part IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 127
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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:
AC Alternating Current
AFUDC Allowance for Funds Used During Construction
AOCI Accumulated Other Comprehensive Income (Loss)
APSC Arkansas Public Service Commission
ARO Asset Retirement Obligations
ASC Accounting Standards Codification
ASU Accounting Standards Update as issued by the FASB
ATM At-the-market equity offering program
BHC Black Hills Corporation; the Company
BLM United States Bureau of Land Management
Btu British thermal unit
CFTC United States Commodity Futures Trading Commission
Chief Operating Decision Maker (CODM) Chief Executive Officer
CIAC Contribution in Aid of Construction
City of Cheyenne Cheyenne, Wyoming
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City of Colorado Springs Colorado Springs, Colorado
City of Gillette Gillette, Wyoming
CPCN Certificate of Public Convenience and Necessity
CPP Clean Power Plan
CP Program Commercial Paper Program
CPUC Colorado Public Utilities Commission
CT Combustion Turbine
CVA Credit Valuation Adjustment
DC Direct Current
DRSPP Dividend Reinvestment and Stock Purchase Plan
DSM Demand Side Management
EPA United States Environmental Protection Agency
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EWG Exempt Wholesale Generator
FASB Financial Accounting Standards Board
FERC United States Federal Energy Regulatory Commission
Fitch Fitch Ratings Inc.
GAAP Accounting principles generally accepted in the United States of America
GHG Greenhouse gases
Happy Jack Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
ICFR Internal Controls Over Financial Reporting
IPP Independent Power Producer
IRC Internal Revenue Code
IRS United States Internal Revenue Service
ITC Investment Tax Credit
kV Kilovolt
LIBOR London Interbank Offered Rate
Mcf Thousand cubic feet
Mcfd Thousand cubic feet per day
MDU Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
MEAN Municipal Energy Agency of Nebraska
MISO Midcontinent Independent System Operator, Inc.
MMBtu Million British thermal units
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
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NERC North American Electric Reliability Corporation
NOx Nitrogen oxide
NOL Net Operating Loss
NPSC Nebraska Public Service Commission
NYSE New York Stock Exchange
OCI Other Comprehensive Income
OPEB Other Post-Employment Benefits
OSHA Occupational Safety & Health Administration
OSM United States Department of the Interior’s Office of Surface Mining
Peak View The 60 MW wind farm owned by Colorado Electric.
PPA Power Purchase Agreement
PRPA Platte River Power Authority
PSA Power Sales Agreement
PTC Production Tax Credit
PUHCA 2005 Public Utility Holding Company Act of 2005
SDPUC South Dakota Public Utilities Commission
SEC United States Securities and Exchange Commission
Silver Sage Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO2 Sulfur dioxide
S&P Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
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SSIR System Safety and Integrity Rider
TCJA Tax Cuts and Jobs Act enacted on December 22, 2017
Utilities Black Hills’ Electric and Gas Utilities
VEBA Voluntary Employee Benefit Association
VIE Variable Interest Entity
WECC Western Electricity Coordinating Council
Working Capacity Total gas storage capacity minus cushion gas
WPSC Wyoming Public Service Commission
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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.
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, such as the COVID-19 pandemic, 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.
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PART I
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 (incorporated in South Dakota in 1941).
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 216,000 electric utility customers in Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 992 MW of generation and 8,892 miles of electric transmission and distribution lines.
Our Gas Utilities segment serves approximately 1,083,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate 4,774 miles of intrastate gas transmission pipelines and 41,838 miles of gas distribution mains and service lines, seven natural gas storage sites, nearly 49,000 horsepower of compression and over 560 miles of gathering lines.
Our Power Generation segment produces electric power from its wind, natural gas and coal-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 and delivers primarily under long-term contracts to adjacent mine-mouth electric generation facilities owned by our Electric Utilities and Power Generation businesses.
Electric Utilities
We conduct electric utility operations through our Colorado, South Dakota and Wyoming subsidiaries. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our retail customers. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services under the Service Guard Comfort Plan and Tech Services.
As of December 31,
As of December 31,
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Capacity and Demand. System peak demand for the Electric Utilities’ retail customers for each of the last three years are listed below:
System Peak Demand (in MW)
Summer Winter Summer Winter Summer Winter
Regulated Power Plants. As of December 31, 2020, our Electric Utilities’ ownership interests in electric generating plants were as follows:
Colorado Electric:
Busch Ranch I (a) Wind Pueblo, Colorado 50% 14.5 2012
Pueblo Airport Generation Gas Pueblo, Colorado 100% 180.0 2011
Pueblo Airport Generation CT Gas Pueblo, Colorado 100% 40.0 2016
South Dakota Electric:
Cheyenne Prairie Gas Cheyenne, Wyoming 58% 55.0 2014
Corriedale (c) Wind Cheyenne, Wyoming 62% 32.5 2020
Wygen III Coal Gillette, Wyoming 52% 57.2 2010
Neil Simpson II Coal Gillette, Wyoming 100% 90.0 1995
Wyodak Plant Coal Gillette, Wyoming 20% 72.4 1978
Neil Simpson CT Gas Gillette, Wyoming 100% 40.0 2000
Lange CT Gas Rapid City, South Dakota 100% 40.0 2002
Ben French Diesel #1-5 Oil Rapid City, South Dakota 100% 10.0 1965
Wyoming Electric:
Cheyenne Prairie Gas Cheyenne, Wyoming 42% 40.0 2014
Cheyenne Prairie CT Gas Cheyenne, Wyoming 100% 37.0 2014
Corriedale (c) Wind Cheyenne, Wyoming 38% 20.0 2020
Total MW Capacity 991.6
________________________
(a) In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act.
(b) The Peak View facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning November 2016. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins.
(c) Corriedale was completed and placed in service on November 30, 2020. This facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning November 2020.
(d) Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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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:
Natural Gas and Diesel Oil (a) 8.4 8.2 6.1
Coal, Natural Gas, Oil and Other Market Purchases 43.3 52.5 52.4
____________________
(a) The diesel-fueled generating units are generally used as supplemental peaking units. Power generated from these units, as a percentage of total power supply, was 0.2%, 0.1% and 0.0% for the years ended December 31, 2020, 2019, and 2018, respectively.
Our Electric Utilities’ 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 were as follows:
Coal, Natural Gas, Oil and Other Market Purchases 44.61 43.73 45.62
Total Purchased Power Weighted Average Cost 41.91 44.23 46.51
Total Weighted Average Fuel and Purchased Power Cost $ 28.52 $ 31.62 $ 32.79
Power Purchase and Power Sales Agreements. We have executed various PPAs to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation. Our Electric Utilities also have various long-term PSAs. Key contracts are disclosed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly operate an electric transmission system, referred to as the Common Use System, with Basin Electric Power Cooperative and Powder River Energy Corporation. Each participant in the Common Use System individually owns assets that are operated together for a single system. The Common Use System also provides transmission service to our Transmission Tie. South Dakota Electric owns 35% of the Transmission Tie. The Transmission Tie is further discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
At December 31, 2020, our Electric Utilities owned the electric transmission and distribution lines shown below:
Utility State Transmission (a)(in Line Miles) Distribution(in Line Miles)
Colorado Electric Colorado 572 3,135
South Dakota Electric South Dakota, Wyoming 1,242 2,565
Wyoming Electric Wyoming 58 1,320
____________________
(a) Electric transmission line miles include voltages of 69 kV and above.
Material transmission services agreements are disclosed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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, cooling demand is often greater in the summer and heating demand in often greater in the winter.
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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 IPPs for the right to supply electric energy and capacity for Colorado Electric when resource plans require additional resources. Additionally, electrification initiatives in our service territories could increase demand for electricity and increase customer growth.
Rates and Regulation. Our Electric Utilities are subject to the jurisdiction of the public utilities commissions in the states where they operate 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, 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:
SD Global Settlement 7.76% Global Settlement $543.9 10/2014 ECA, TFA, EIA 70%
__________
(a) For both Colorado Electric and Wyoming Electric, transmission investments are recovered through retail rates rather than FERC Transmission Tariffs.
(b) Includes $136.9 million in 2020 rate base for the 2020 Projected Common Use System formula rate that is updated annually and $17.1 million in rate base for the 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. We have cost adjustment mechanisms for our Electric Utilities, subject to thresholds noted above, that allow us to pass the prudently-incurred cost of fuel and purchased power 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. In addition, some states allow for recovery of new capital investment placed in service between base rate reviews through approved rider tariffs. These tariffs allow the utility a return on the investment.
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A summary of mechanisms we have in place are shown in the table below:
Electric Utility Jurisdiction Cost Recovery Mechanisms
Colorado Electric þ þ þ þ þ þ
South Dakota Electric (SD) (a) þ þ þ þ þ
South Dakota Electric (WY) þ þ þ þ
South Dakota Electric (FERC) (b) þ
Wyoming Electric þ þ þ þ
__________
(a) South Dakota Electric’s Environmental Cost (EIA) and Transmission Capital (TFA) tariffs were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020, South Dakota Electric received approval from the SDPUC to extend the 6-year moratorium period by an additional 3 years whereby these recovery mechanisms will not be effective prior to July 1, 2026. For additional information, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. On December 1, 2020, South Dakota Electric (SD) terminated its Energy Efficiency program.
(b) South Dakota Electric has an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff.
Tariff Filings. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for tariff filings and additional information regarding current electric regulatory activity.
Operating Statistics. See a summary of key operating statistics in the Electric Utilities segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Gas Utilities
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 1,083,000 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 to our regulated customers. Black Hills Energy Services provides natural gas supply to approximately 52,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide services under the Service Guard Comfort Plan, Tech Services and HomeServe.
As of December 31,
As of December 31,
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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.
In addition to company-owned natural gas storage assets in Arkansas, Colorado and Wyoming, we also contract with third-party transportation providers 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, 2020:
The following table summarizes certain information regarding our system infrastructure as of December 31, 2020:
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. 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 temperatures and precipitation, which can affect 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. Additionally, electrification initiatives in our service territories could negatively impact demand for natural gas and decrease customer growth. 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 charge for transporting the gas through our distribution network.
Rates and Regulation. Our Gas Utilities are subject to the jurisdiction of the public utility commissions in the states where they operate. 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, 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.
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Our Gas Utilities are authorized to use natural gas cost recovery mechanisms allowing rate adjustments reflecting changes in the wholesale cost of natural gas and recovery of all the costs prudently incurred in purchasing gas for customers. In addition to natural gas cost recovery mechanisms, other recovery mechanisms, which vary by utility, allow us to recover certain costs or earn a return on capital investments, such as energy efficiency plan costs and system safety and integrity investments.
The following table provides regulatory information for each of our natural gas utilities:
__________
(a) Arkansas Gas return on rate base is adjusted to remove current liabilities from rate review capital structure for comparison with other subsidiaries.
(b) Arkansas Gas rate base is adjusted to include current liabilities for comparison with other subsidiaries.
(c) Information above reflects the NPSC order received on January 26, 2021. For additional information, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
(d) The Choice Gas Program mechanisms are applicable to only a portion of Nebraska Gas and Wyoming Gas customers.
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
Arkansas Gas þ þ þ þ þ
Colorado Gas þ þ
RMNG(a) þ
Iowa Gas þ þ þ
Kansas Gas þ þ þ þ þ
Nebraska Gas þ þ þ
Wyoming Gas þ þ þ
__________
(a) RMNG, which is an intrastate transmission pipeline that provides natural gas transmission and wholesale services in western Colorado, has an SSIR recovery mechanism. The other cost recovery mechanisms are not applicable to RMNG.
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Tariff Filings. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current natural gas regulatory activity.
Operating statistics. See a summary of key operating statistics in the Gas Utilities segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Utility Regulation Characteristics
State Renewable Energy Standards
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, 2020, we were subject to the following renewable energy portfolio standards or objectives:
•Colorado. Colorado adopted a renewable energy standard in 2004 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 for 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.
In 2019, the State of Colorado approved Senate Bill 236, which required qualified retail electric utilities (more than 500,000 customers) to submit a Clean Energy Plan to meet an 80% carbon reduction goal by 2030 based upon 2005 baseline levels. While Colorado Electric is not required to submit a Clean Energy Plan, the state also passed House Bill 1261 which established state-wide emission goals for greenhouse gas emitting activities that apply to Colorado Electric. Both House Bill 1261 and Senate Bill 236 include provisions that allow Colorado Electric to submit a voluntary Clean Energy Plan with a goal of 80% reduction by 2030. On January 7, 2021, Colorado Electric announced it will file a Clean Energy Plan with the CPUC voluntarily in 2022.
On September 23, 2020, Colorado Electric received approval from the CPUC for its preferred solar bid request in support of its Renewable Advantage program. The program plans to add up to 200 MW of renewable energy in Colorado by the end of 2023, which will contribute towards the aforementioned 80% carbon reduction goal by 2030. When Renewable Advantage comes online in 2023, more than half of Colorado Electric’s generation mix will be renewable sources, leading to an approximate 70% reduction in GHG emissions by 2024.
•South Dakota. South Dakota adopted a renewable portfolio objective in 2008 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 not issued a renewable energy portfolio standard.
In November 2020, we announced clean energy goals to reduce GHG emissions that are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. See more information in the Key Elements of our Business Strategy within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Federal Regulation
Energy Policy Act. The Energy Policy Act of 2005 included provisions to create an Electric Reliability Organization, which is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards will be subject to fines and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
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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 and Power 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 whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and also a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.
Power Generation
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, 2020, we held varying interests in independent power plants with a total net ownership of 423 MW.
We produce electric power from our generating facilities and sell the electric capacity and energy, primarily to affiliates under a combination of mid- to long-term contracts, which mitigates the impacts of volatility in future power prices and fluctuations in demand.
As of December 31, 2020, the power plant ownership interests held by our Power Generation segment include:
Pueblo Airport Generation (a) Gas Pueblo, Colorado 50.1% 200.0 2012
Busch Ranch I (b) Wind Pueblo, Colorado 50.0% 14.5 2012
Busch Ranch II (c) Wind Pueblo, Colorado 100.0% 60.0 2019
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(a) In 2016, Black Hills Electric Generation sold a 49.9% noncontrolling interest in Black Hills Colorado IPP to a third party. See Note 14 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
(b) In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act.
(c) The Busch Ranch II and Top of Iowa facilities qualify for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date each facility was originally placed in service.
(d) Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Power Sales Agreements and Operating Agreements. Our Power Generation facilities have various mid- to long-term power sales agreements and operating agreements. Key contracts are disclosed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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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 IPPs in some regions. To date, these initiatives have not had a material impact on our Power Generation segment.
The Energy Policy Act of 1992 and Public Utility Holding Company Act of 2005 (PUHCA 2005). PUHCA 2005 reiterated the definition and benefits of Exempt Wholesale Generator (EWG) status. Under PUHCA 2005, an EWG is an entity or generator engaged, directly or indirectly through one or more affiliates, exclusively in the business of owning, operating or both owning and operating all or part of one or more eligible facilities and selling electric energy at wholesale. Though EWGs are public utilities within the definition set forth in the Federal Power Act and are subject to FERC regulation of rates and charges, they are exempt from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with three EWGs, Wygen I, Pueblo Airport Generating and Top of Iowa. Each of these three EWG’s have been granted market-based rate authority.
Operating statistics. See a summary of key operating statistics in the Power Generation segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Mining
Our Mining segment operates a single coal mine through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC mine, which we acquired in 1956 from Homestake Mining Company, is located in the Powder River Basin. We produced approximately 3.7 million tons of coal in 2020.
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 trended upwards over the last fifteen years. However, the overburden ratio at December 31, 2020 was 2.17 which decreased from 2.30 in the prior year as we mined in areas with lower overburden. We expect our stripping ratio to increase to approximately 2.27 by the end of 2021 as we mine in areas with higher overburden.
Mining rights to the reserves are based on three federal leases and one state lease. The federal leases expire between March 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. The federal lease expiring March 31, 2021 relates to an area we are no longer mining and will not be renewed. The Biden Administration recently issued an executive order that suspends new oil and gas leases on federal lands and eliminates fossil fuel subsidies. However, this moratorium does not apply to federal mining leases and we have not received federal subsidies.
We pay federal and state royalties of 12.5% of the selling price of all coal. As of December 31, 2020, we estimated our recoverable reserves to be approximately 182 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 reserve life is equal to approximately 49 years at the current production levels. Our recoverable reserve estimates are periodically updated to reflect past 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 reserves include reserves that can be economically and legally extracted at the time of their determination.
Substantially all of the 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 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 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, subject to adjustments for planned outages and other contract terms. This contract expires December 31, 2022 and negotiations to extend the contract are ongoing. 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 and other contract terms;
•The 110 MW Wygen III power plant jointly owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons each year;
•The 90 MW Wygen I power plant jointly owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons each year; and
•Certain regional industrial customers served by truck to which we sell a total of approximately 300,000 tons 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 sales to a specified return on our mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above Moody’s A-Rated Utility Bond Index applied to our Mining investment base.
The price of unprocessed coal sold to PacifiCorp for the Wyodak Plant is determined by the supply agreement described above. The agreement included a price adjustment in 2019. The price adjustment essentially allowed us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment was based on market price plus considerations for the avoided costs of rail transportation and an unloading facility, which PacifiCorp would have to incur if it purchased from another mine. In addition, the agreement also provided for the monthly escalation of price based on an escalation factor.
In October 2019, negotiations were completed for the price re-opener in the contract with the 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 is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of an 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).
WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement through June 30, 2038. Currently, this agreement uses a base price that includes price escalators and quality adjustments and includes actual cost per ton plus a margin equal to the yield for Moody’s A-Rated Utility Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. Effective January 1, 2022, in conjunction with the new Wygen I 60 MW PPA, WRDC’s current coal supply agreement will be revised using pricing that will be cost-based to regulate earnings to a specified return on the cost-depreciated investment base. For additional information regarding the new Wygen I 60 MW PPA, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Competition. Our strategy is to sell the majority of our production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically, any off-site sales have been to consumers within close proximity to the WRDC mine. Rail transport market opportunities for WRDC are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC mine is served by only one railroad, resulting in less competitive transportation rates.
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 and availability considerations 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 completed during production and after mining has finished. Under applicable law, we must submit applications to, and receive approval from, the Wyoming Department of Environmental Quality for any mining and reclamation plans that provide 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 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 and we are currently in the process of renewing this permit. Based on extensive reclamation studies, we have accrued approximately $13 million for reclamation costs as of December 31, 2020. See additional information in Note 7 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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Operating statistics. See a summary of key operating statistics in the Mining segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Environmental Matters
In November 2020, we announced clean energy goals to reduce GHG emissions that are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. See more information in Key Elements of our Business Strategy within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
Environmental Management System (EMS). We operate an EMS that is composed of environmental policies and procedures, voluntary initiatives, objectives and annual targets, operational controls, training, a sophisticated task scheduling/tracking and document control system, and a continuous improvement process. The program attained Colorado’s highest level in their Environmental Leadership Program (Gold Level status in 2014) and has continued this status through 2020.
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. Presently, we have facilities in our natural gas transmission operations affected by the methane reduction rules.
Our operations are 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 that we will adhere to. We developed a corporate-wide methane control strategy to address GHG emissions. As a proactive measure in reducing methane emissions beyond current regulatory requirements, we have entered into the EPA’s Methane Challenge Program. This is a voluntary program founded by the EPA in collaboration with oil and natural gas companies that recognizes companies that make specific and transparent commitments to reduce methane emissions.
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. 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 down the power plant if we anticipate the emission limit will be exceeded. There have been limited instances of the trip logic mechanism being used and we experienced zero exceedances during 2020.
Regional Haze (Impacts to the Wyodak 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, overruled it in a Federal Implementation Plan (FIP) and proposed a Selective Catalytic Reactor to be installed to control NOx emissions. This would cost South Dakota Electric approximately $27 million due to its 20% ownership of the Wyodak Plant. PacifiCorp and the State of Wyoming challenged the EPA’s determination. Prior to proceeding to court, PacifiCorp and the EPA reached a verbal agreement on December 16, 2020, to limit operating hours and determined that low-NOx burners would be considered appropriate to control NOx emissions. This proposed agreement was published in the Federal Register, but remains in the public comment period until March 1, 2021. The final agreement must be published in the Federal Register and approved in Wyoming’s State Implementation Plan through the rule making process.
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 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. The mine makes every effort to reduce these impacts by monitoring blasts, modifying blast techniques to reduce blast vibration, applying dust suppression controls on roads and reclaiming lands to reduce windblown dust.
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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. As of December 31, 2020, our Gas Utilities have two active FMGP sites, which are located in Council Bluffs, Iowa, and McCook, Nebraska. At the Council Bluffs site, the EPA issued an order for the responsible parties to proceed with an Engineering Evaluation and Cost Analysis (EECA) to clean up the site. Three viable Potential Responsible Parties (PRP) continue to deny their legal attachment to the site. The Company will continue conducting the EECA and anticipates pursuing the PRP’s through legal action. There is currently no action being taken at the McCook, Nebraska site. A third-party initially indicated they intend to manage and pay for the clean-up at this site. However, after further investigation, the third-party assessed they owned the property after the gas plant ceased operations. We expect to conduct an assessment to determine viable PRPs.
For additional information, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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 (ACE) rule. This rule focused on heat-rate improvements on coal-fired boiler units and applied only to our coal-fired plants. The Company’s coal-fired plants subject to the rule had implemented or planned to implement a majority of the efficiency requirements listed in the rule. On January 19, 2021, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule. The court remanded the regulation regarding carbon dioxide emissions from existing power plants back to the EPA for reconsideration. Currently, there is no rule governing power plant GHG emissions and it is uncertain when a new rule will be promulgated.
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 ash is used for backfill reclamation in areas previously mined. The Office of Surface Mining (OSM) was considering CCR rules that would apply to the mine, but these rules were not proposed during the Trump administration. We will continue to monitor to see if the Biden administration pursues these rules.
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 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Other Properties
In addition to the properties previously disclosed in the sections above, we own or lease several facilities throughout our service territories including a corporate headquarters building and various office, service center, storage, shop and warehouse space. 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.
Human Capital Resources
Overview
Black Hills Corporation is committed to supporting operational excellence by attracting, motivating, retaining and encouraging the development of highly qualified employees. Our employees’ drive and dedication to their work, and their commitment to the safety of our customers and their fellow employees, allows Black Hills Corporation to successfully grow and manage our business year over year. The impacts of COVID-19 to our businesses and employees are discussed in the Company Highlights within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.
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Our Team As of December 31, 2020
Total employees 3,011
Gender diversity (women as a % of total employees) 26%
Women in executive leadership positions (a) 31%
Ethnic diversity (non-white employees as a % of total) 11%
Military veterans 16%
Represented by a union 25%
For the year ended December 31, 2020
Number of external hires 299
External hires gender diversity (as a % of total external hires) 29%
External hires ethnic diversity (as a % of total external hires) 16%
Turnover rate (b) 8%
Retirement rate 3%
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(a) Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.
(b) Includes voluntary and involuntary separations, but excludes internships.
Total Employees
Number of Employees
Electric Utilities 379
Power Generation and Mining 60
Corporate and Other 1,335
At December 31, 2020, approximately 21% of our total employees and 23% 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.
Collective Bargaining Agreements
At December 31, 2020, certain employees of our Electric Utilities and Gas Utilities were covered by the collective bargaining agreements as shown in the table below. We have not experienced any labor stoppages in decades.
Total Electric Utilities 258
Total Gas Utilities 484
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Attraction
Continuous attraction of qualified team members is critical to our ability to serve our 1.3 million customers safely and efficiently. We actively recruit diverse candidates and continuously evaluate our interviewing and hiring practices to ensure equitable pay and processes. Our attraction efforts include the use of multiple nation-wide job boards, local college and high school outreach programs, a strong college internship program and participation in national and local job fairs. Another key area of attraction is our commitment to our military personnel and veterans. We have targeted attraction efforts specific to military personnel transitioning into civilian life and for veterans of all types.
Diversity & Inclusion
At Black Hills Corporation, we believe in the benefits of diversity, equity and inclusion. We believe that a diverse workforce will assist us in achieving our goals of becoming the safest utility in the nation, providing exceptional customer service and achieving new levels of growth in a rapidly evolving industry. Workforce diversity trends, including diverse new hires, promotions and turnover, are monitored at regular intervals.
Development and Retention
Retaining and developing team members is critical to our continued success. Our retention efforts include competitive compensation programs, career development resources for all employees and internal training programs. Our compensation programs are designed to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective and legally compliant. Our career development resources include management onboarding, leadership development programs, mentoring programs, individual development assessments and more. Internal training opportunities include corporate-wide trainings such as our code of conduct and specialized training opportunities for different job functions. Our Field Career Path Program (FCPP) promotes career growth through established standards of knowledge, skills, abilities and performance.
ITEM 1A.RISK FACTORS
The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business operations, financial condition, results of operations or cash flows are described below. These risk factors, along with other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.
STRATEGIC RISKS
Our continued success is dependent on execution of our strategic business plans including our growth strategy.
Our success depends, in significant part, on our ability to execute our strategic business plans, including our growth strategy. Our plans and strategy include reducing GHG emissions for our Electric Utilities and Gas Utilities, transforming the customer experience, growing our electric and natural gas customer load, pursuing operating efficiencies and modernizing our utility infrastructure. Our current plans and strategy may be negatively impacted by disruptive forces and innovations in the marketplace, changing political, business or regulatory conditions, and technology advancements.
In addition, we have significant capital investment programs planned for the next five years that are key to our strategic business plans. The successful execution of our capital investment program depends on, or could be affected by, a variety of factors that include, but are not limited to: weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, availability of materials, governmental approvals and permitting, regulatory cost recovery and return on investment.
An inability to successfully and timely adapt to changing conditions and execute our strategic plans, including our growth strategy could materially affect our financial operating results including earnings, cash flow and liquidity.
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Customer growth and usage in our service territories may fluctuate with economic conditions, emerging technologies or responses to price increases.
Our financial operating results are impacted by energy demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction in consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, 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.
REGULATORY, LEGISLATIVE AND LEGAL RISKS
We may be subject to future laws, regulations, or actions associated with climate change, including those relating to fossil-fuel generation and GHG emissions, which could increase our operating costs or restrict our market opportunities.
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, store 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.
There is uncertainty surrounding climate regulation due to legal challenges to some current regulations and anticipated new federal and/or state climate legislation and regulation. The Biden administration has issued executive orders aimed at reducing GHG emissions and declared climate change a national security policy for the first time. 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 capacity reductions of coal-fired power generation facilities and potential increased production from our combined cycle natural gas-fired generating units. 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 natural gas storage facilities or our 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. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial condition or cash flows.
Future GHG constraints designed to minimize emissions from natural gas could likewise result in increased costs and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas. Certain cities in our operational footprint are focused on electrification and have adopted initiatives to prohibit the construction of new natural gas distribution facilities. Any such initiatives and legislation could have a material impact on our results of operations, financial condition and cash flows.
We may be subject to unfavorable or untimely federal and state regulatory outcomes.
Our regulated Electric and Gas Utilities are subject to cost-of-service/rate-of-return 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 customer rates are regulated by either the FERC or the respective state utility regulatory authority based on an analysis of our costs and investments, as reviewed and approved in a regulatory proceeding. 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 or timely recovery of our costs and the allowed return on invested capital. In addition, adverse rate decisions, including rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investments or rate reductions, could be influenced by competitive, economic, political, legislative, public perception and regulatory pressures and adversely impact results of operations, financial condition and cash flows.
Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs or integrity capital investments) outside of a base rate review in order to stabilize customer rates and reduce regulatory lag. If regulators decide to discontinue these tariff-based recovery mechanisms, it could negatively impact results of operations, financial condition and cash flows.
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Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements.
Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions (i.e. SO2, NOx, volatile organic compounds, particulate matter and GHG), 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 or inability to comply with evolving environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.
Our business segments may not be successful in recovering increased 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 our business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.
Legislative and regulatory requirements may lead to increased costs and result in compliance penalties.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many 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 financial operating results including earnings, cash flow and liquidity.
Municipal governments may seek to limit or deny our franchise 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. We also cannot quantify the impact that such action would have on the remainder of our business operations.
Changes in Federal tax law may significantly impact our business.
We are subject to taxation by the various taxing authorities at the federal, state and local levels where we do business. Similar to the TCJA, sweeping legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes may include numerous provisions that affect businesses, including changes to U.S. corporate tax rates, business-related exclusions, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which the effect of a change in corporate tax rate will impact our utility customers and the time period over which the impact will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.
OPERATING RISKS
Our financial performance depends on the successful operation of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities, and a coal mine.
The risks associated with management of these operations include:
•Inherent dangers. Electricity and natural gas can be dangerous to employees and the general public. Failures of or contact with power lines, natural gas pipelines or service facilities and equipment may result in fires, explosions, property damage and personal injuries, including death. 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;
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•Weather, natural conditions and disasters. Severe weather events, such as snow and ice storms, fires, tornadoes, strong winds, significant thunderstorms, flooding and drought, could negatively impact operations, including our ability to provide energy safely, reliably and profitably and our ability to complete construction, expansion or refurbishment of facilities as planned;
•Acts of sabotage, terrorism or other malicious attacks. Damage to our facilities due to deliberate acts could lead to outages or other adverse effects;
•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;
•Equipment and processes. Breakdown or failure of equipment or processes, unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations;
•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 utility services and satisfy our contractual obligations may be hindered;
•Natural gas supply for generation and distribution. Our regulated utilities and non-regulated entities purchase natural gas from a number of 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 natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations;
•Replacement 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 cost of complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate
and our results of operations;
•Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and contractual agreements, including those that 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 laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;
•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, 2020, approximately 23% 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 unions;
•Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses; and
The ongoing operation of our business involves the risks described above, in addition to risks associated with threats to 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 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.
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Cyberattacks, terrorism, or other malicious acts targeting our key technology systems 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, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and 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 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 associated revenues, as well as significant expense to repair damages and remedy security breaches. In addition, 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. Despite our implementation of security measures and safeguards, all of our technology systems may still be vulnerable to disability, failures or unauthorized access.
Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.
Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. 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 financial operating results, including earnings, cash flow and liquidity.
FINANCIAL RISKS
A sub-investment grade credit rating could impact our ability to access capital 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 investment grade credit ratings could impair our ability to refinance or repay our existing debt and complete new financings on reasonable terms, if at all. A credit rating downgrade, particularly to sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities, potentially significantly increasing our cost of capital and other associated operating costs which may not be recoverable through existing regulatory rate structures and contracts with customers.
Our use of derivative financial instruments as hedges against commodity prices and financial market risks could result in material financial losses.
We use various financial and physical derivatives, including futures, forwards, options and swaps to manage commodity price and interest rate 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. For Black Hills Energy Services under the Choice Gas Program, and in certain instances within our regulated Utilities where unrealized and realized gains and losses from derivative instruments are not approved for regulatory accounting treatment, fluctuating commodity prices may cause fluctuations in reported financial results due to mark-to-market accounting treatment.
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.
Additionally, our exchange-traded futures contracts are subject to futures margin posting requirements. To the extent we are unable to meet these requirements, this 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. Further, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.
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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 to the holding company because these subsidiaries depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 9 of our Notes to Consolidated Financial Statements 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.
A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, 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.
We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.
Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers. Additionally insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. A loss for which we are not adequately insured could materially affect our financial results. The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient to cover all liabilities to which the Company may be subject, including liability and losses associated with wildfire, natural gas and gas storage field explosions, cyber-security breaches, environmental hazards and natural disasters.
Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and other postretirement benefit plans.
Assumptions related to interest rates, expected return on investments, mortality and other key actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. An 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 liquidity.
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Costs associated with our healthcare plans and other benefits 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 required, and likely will continue to require, changes to our current employee benefit plans and supporting administrative 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 is no assurance that the state utility commissions will allow recovery of these increased costs. The rising employee benefit costs, or inadequate recovery of such costs, may adversely affect our financial operating results including earnings, cash flow, or liquidity.
PANDEMIC RISK
Our business operations, results of operations, financial condition and cash flows could be adversely affected by the coronavirus (COVID-19) pandemic.
We have responded to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.
For the year ended December 31, 2020, the COVID-19 pandemic had a limited net financial impact on our business operations, financial condition and cash flows. In particular, we experienced:
•Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;
•Increased costs due to sequestration of mission-critical and essential employees;
•Lower commercial and certain transport volumes partially offset by higher electric and natural gas residential usage;
•Waived customer late payment fees;
•Reduced availability of our employees;
•Increased costs for personal protection equipment and cleaning supplies;
•Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;
•Minimal impacts to the availability of our contractors;
•Minimal decline in the funded status of our pension plan;
•Minimal interest expense increase due to disruptions in the Commercial Paper markets; and
•Reduced training, travel, and outside services related expenses.
Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business operations, financial condition and cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:
•Adverse impacts on our strategic business plans, growth strategy and capital investments;
•Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;
•Further reduction in the availability of our employees and contractors;
•Increased costs as a result of our preventative measures, such as sequestration of essential employees and facility cleaning services;
•Increased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment;
•Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;
•Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;
•Deterioration of the credit quality of our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;
•Impairment of goodwill or long-lived assets;
•Adverse impacts on our ability to construct and operate facilities;
•Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;
•Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;
•Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;
•Adverse impact on our liquidity position and cost of and ability to access funds from financial institutions and capital markets; and
•Delays in our ability to change rates through regulatory proceedings.
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To date, we have experienced limited impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our results of operations, financial condition and cash flows.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.
ITEM 3.LEGAL PROCEEDINGS
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 3, “Commitments, Contingencies and Guarantees”, of our Notes to 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 the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 of this Annual Report.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Linden R. Evans, age 58, 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 19 years of experience with the Company.
Scott A. Buchholz, age 59, has been our Senior Vice President of Strategic Initiatives since July 2020. He served as Senior Vice President — Chief Information Officer from the closing of the Aquila Transaction in 2008 to 2020. 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 40 years of experience with the Company, including 28 years with Aquila. Mr. Buchholz plans to retire on March 8, 2021.
Brian G. Iverson, age 58, 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 17 years of experience with the Company.
Richard W. Kinzley, age 55, 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 21 years of experience with the Company.
Jennifer C. Landis, age 46, 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 19 years of experience with the Company.
Stuart Wevik, age 59, 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 35 years of experience with the Company.
Erik Keller, age 57, joined the Company as Senior Vice President and Chief Information Officer on July 27, 2020. Prior to joining the company, he was an Information Technology consultant to Ontic Inc., a global provider of parts and services for legacy aerospace platforms, from January 2020 to July 2020, and Chief Information Officer for BBA Aviation, a global aviation support and aftermarket services provider, from February 2012 to January 2020.
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PART II
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 January 31, 2021, we had 3,537 common shareholders of record and 46,737 beneficial owners, representing all 50 states, the District of Columbia and 6 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 27, 2021 meeting, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend rate of $2.26 per share. This equivalent rate, if declared and paid in 2021, will represent 51 consecutive years of annual dividend increases.
For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity and Capital 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