ITEM 1A.RISK FACTORS
The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect our 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 building sustainable operations and supporting the Energy Transition; consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operating efficiencies. 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 and inflationary cost 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 could materially affect our financial operating results including earnings, cash flow and liquidity.
Customer growth and usage in our service territories may fluctuate with economic conditions, emerging technologies, political influences 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 could 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 non-regulated 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. 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 or conversion to natural gas, and potential increased production from our combined cycle natural gas-fired generating units. Additional 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.
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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 among fuel alternatives. Certain cities in our operational footprint are focused on electrification and are considering initiatives that may restrict the direct use of natural gas in homes and businesses. Any such initiatives and legislation could have a negative 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 based on an analysis of our costs and investments, as reviewed and approved in regulatory proceedings. 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 with a reasonable 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, including incremental costs from Winter Storm Uri, 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.
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 government 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 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, TSA 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.
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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 operate. 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 corporate tax rates, business-related exclusions, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which a change in corporate tax rate will affect our utility customers and the time period over which that change 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 managing 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;
•Weather, natural conditions and disasters including impacts from climate change. Severe weather events, such as snow and ice storms (e.g., Winter Storm Uri), 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. Climate change may intensify these events or increase the frequency of occurrence;
•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 natural 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, sabotage, cyber-attacks 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;
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•Supply chain disruptions. We rely on various suppliers in our supply chain for the materials necessary to execute on our capital investment program. Our supply chain, material costs, and capital investment program may be negatively impacted by unanticipated price increases due to factors exacerbated by the COVID-19 pandemic, such as inflation, including wage inflation, or due to supply restrictions beyond our control or the control of our suppliers;
•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. There is competition and a tightening market for skilled employees. During the COVID-19 pandemic and subsequent recovery, there is a national trend of increased employee turnover. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2021, approximately 22% of our Electric Utilities and Gas Utilities employees were eligible for retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk with approximately 25% of our employees are represented by unions; and
•Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses.
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, 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.
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 natural 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 maintain cyber risk insurance to mitigate a portion, but not all, or these risks and losses.
In May and July 2021, the TSA issued security directives that included several new cybersecurity requirements for critical pipeline owners and operators. Among these requirements is the implementation of specific mitigation measures to protect against ransomware attacks and other known threats to information and operational technology systems; development and implementation of a cybersecurity contingency and recovery plan; and performance of a cybersecurity architecture design review. We are currently implementing several of these directives and evaluating the potential effect of several others on our operations and facilities, as well as the potential cost of implementation, and will continue to monitor for any clarifications or amendments to these directives.
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.
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FINANCIAL RISKS
A sub-investment grade credit rating could impact our ability to access capital markets.
Our senior unsecured debt 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 may not consistently 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.
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 future earnings, capital requirements and financial conditions to fund such dividends. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 8 of the 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.
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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 climate change, wildfire, natural gas and 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 our pension and other postretirement benefit 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.
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 natural 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, however, there is no assurance that the 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
The ongoing COVID-19 pandemic, including its variants, or any other pandemic and the associated impact on business and economic conditions could negatively affect our business operations, results of operations, financial condition and cash flows.
The scale and scope of the COVID-19 outbreak, the resulting pandemic or any other future pandemic, and the associated impact on the economy and financial markets could adversely affect the Company’s business, results of operations and financial condition. As a provider of essential services, the Company has an obligation to provide electric and natural gas services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations.
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Although the impact of the COVID-19 pandemic and its variants to our 2021 results of operation was not significant, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. We also cannot predict the impact of COVID-19 on the health of our employees, our supply chain or our ability to mitigate higher costs associated with managing through the COVID-19 pandemic.
As recovery from the COVID-19 pandemic continues, additional uncertainties have emerged, including the impacts of:
•vaccine mandates and testing requirements on our workforce;
•inflation increasing prices of commodities and materials, outside services, employee costs and interest rates;
•supply chain disruptions on the availability and cost of materials; and
•labor shortages and increased turnover on costs of retaining and attracting employees.
The situation remains fluid and it is difficult to predict with certainty the potential impact of the COVID-19 pandemic, or any other future pandemic, on our financial operating results including earnings, cash flows and liquidity.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
See Item 1 for a description of our principal business properties.
In addition to the properties disclosed in the Item 1, 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.
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 the 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 59, 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 20 years of experience with the Company.
Brian G. Iverson, age 59, 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 18 years of experience with the Company.
Erik D. Keller, age 58, 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.
Richard W. Kinzley, age 56, 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 22 years of experience with the Company.
Jennifer C. Landis, age 47, 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 20 years of experience with the Company.
Stuart A. Wevik, age 60, 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 36 years of experience with the Company. Mr. Wevik intends to retire on June 1, 2022.
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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, 2022, we had 3,475 common shareholders of record and 60,937 beneficial owners, representing all 50 states, the District of Columbia and 7 foreign countries.
COMPARATIVE STOCK PERFORMANCE
The following performance graph compares the cumulative total stockholder return from Black Hills Corporation common stock, as compared with the S&P 500 Index, S&P 500 Utilities index, and our performance peer group for the past five years. The graph assumes an initial investment of $100 on December 31, 2016, and assumes all dividends were reinvested. The stockholder return shown below for the five-year historical period may not be indicative of future performance. The information in this "Comparative Stock Performance" section shall not be deemed to be "soliciting material" or to be "filed" with the Securities and Exchange Commission or subject to Regulation 14A or 14C, or to the liabilities of Section 18 of the Securities Exchange Act of 1934.
Years ended December 31,
____________________
(a) Performance Peer Group represents the list of 20 utility and energy industry companies used in our 2021 Proxy Statement which was filed with the SEC on March 18, 2021.
DIVIDENDS
For information concerning dividends, our dividend policy and factors that may limit our ability to pay dividends, see “Key Elements of our Business Strategy” and “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
There were no unregistered securities sold during 2021.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
See Item 12 in this Annual Report on Form 10-K for information regarding Securities Authorized for Issuance Under Equity Compensation Plans.
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ISSUER PURCHASES OF EQUITY SECURITIES
The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2021:
____________________
(a) Shares were acquired under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.
ITEM 6.(RESERVED)
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Executive Summary
We are a customer-focused energy solutions provider that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission— and our primary focus — is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.
We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company considers itself a domestic electric and natural gas utility company.
The Company has provided energy and served customers for 138 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations.
An important component of our strategy involves sustainable operations and supporting the Energy Transition. How we operate our company for the social good has never been more important. We are committed to cleaner energy and a low carbon future, integrating the Energy Transition and more renewable energy into our overall strategy and decision making. For this important work, we are Ready to serve. In addition, we are committed to a more sustainable future by better managing our impacts to the planet, whether that is water usage, recycling, biodiversity, or other important measures, and remaining focused on our human capital through diversity and inclusion.
Our emphasis is on consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operating efficiencies. These areas of focus will present the company with significant investment needs as we harden our infrastructure systems, meet customer growth and fulfill customer expectations for cleaner energy services. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective solutions.
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Key Elements of our Business Strategy
Modernize and operate utility infrastructure to provide customers with safe, reliable, cost-effective electric and natural gas service. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that spans nearly 1,600 miles. Our Electric Utilities own and operate 1,481.5 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities own and operate 47,000 miles of natural gas transmission and distribution pipelines.
A key strategic focus is to modernize and harden our utility infrastructure to meet customers’ and communities’ varied energy needs, ensure the continued delivery of safe, reliable and cost-effective energy and reduce GHG emissions intensity. In addition, we invest in the expansion, capacity and integrity of our systems to meet customer growth.
We rigorously comply with all applicable federal, state and local regulations and strive to consistently meet industry best practice standards. A key component of our modernization effort is the development of programs by our Electric and Gas Utilities to systematically and proactively replace aging infrastructure on a system-wide basis.
To meet our electric customers’ continued expectations of high levels of reliability, a key strength of the Company, our Electric Utilities utilize an integrity program to ensure the timely repair and replacement of aging infrastructure. In alignment with this program, in November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The 285-mile, multi-phase transmission expansion project will serve the growing needs of customers enhancing the resiliency of its overall electric system and expanding access to power markets and renewable energy resources. The project will enable Wyoming Electric to maintain top-quartile reliability and support further economic growth in the Cheyenne area. Wyoming Electric plans to file an application with the WPSC seeking approval for the project in the first quarter of 2022. Following approval, construction would commence in early 2023.
Our Gas Utilities utilize a programmatic approach to system-wide pipeline replacement, particularly in high consequence areas. Under the programmatic approach, obsolete, at-risk and vintage materials are replaced in a proactive and systematic time frame. We have removed all cast- and wrought-iron from our natural gas transmission and distribution systems and continue to replace aging infrastructure through programs that prioritize safety and reliability for our customers. Our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments, between rate reviews, which allow timely recovery of costs incurred in repairing and replacing the gas delivery systems with a return on the investment.
As of December 31, 2021, we estimate our five-year capital investment to be approximately $3.2 billion, with most of that investment targeted toward upgrading existing utility infrastructure supporting customer and community growth needs, and complying with safety requirements. Our actual 2021 and forecasted capital expenditures for the next five years from 2022 through 2026 are as follows (in millions):
Actual (a) Forecasted
(in millions)
Incremental projects (b) — — — — 60 140
____________________
(a) Includes accruals for property, plant and equipment as disclosed as supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements in this Annual Report on Form 10-K.
(b) These represent projects that are being evaluated by our segments for timing, cost and other factors.
Efficiently plan, construct and operate power generation facilities to serve our Electric Utilities. We best serve customers and communities when generation is vertically integrated into our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to supply cost-effective electricity to our customers. These generation assets can be rate-based or non-regulated assets within our Electric Utilities segment. However, we believe that generation assets that are rate-based provide long-term benefits to customers. In the fourth quarter of 2021, we revised our operating segments to align with our vertically integrated business model for our Electric Utilities. Our power generation and mining businesses, which were previously presented as separate operating segments, are now part of our vertically integrated Electric Utilities segment.
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Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs (operations located near energy hubs), efficiency in converting fuel into energy and low per unit operating and maintenance costs. In addition, we operate our plants with high levels of Availability as compared to industry benchmarks.
Rate Base Generation: We continue to believe that customers are best served when the power generation facilities are owned and rate-based by our Electric Utilities. Rate-based generation assets offer several advantages for customers and shareholders, including:
•When generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run; especially when compared to power otherwise purchased from the open market through wholesale contracts or PPAs that are periodically re-priced to reflect current and varying market conditions;
•Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;
•The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of capital; and
•Investors are provided a long-term and stable return on their investment.
Integrated Generation: Our Electric Utilities segment also contains a power generation business that owns non-regulated generating facilities that are contracted through long-term power purchase agreements with our electric utilities. Our power generation business has an experienced staff with significant expertise in planning, building and operating power plants. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the company’s generation assets. This business competitively bids for energy and capacity through requests for proposals by our Electric Utilities for energy resources necessary to serve customers. This business can bid competitively due to construction expertise, fuel supply advantages and by co-locating new plants at our existing Electric Utilities’ energy complexes, reducing infrastructure and operating costs. All power plants within this business, except Top of Iowa, are contracted to our Electric Utilities under long-term contracts and are located at our utility-generating complexes, including Busch Ranch, Pueblo Airport Generation, and the Gillette, Wyoming energy complex, and are physically integrated into our Electric Utilities’ operations.
Generation Fuel Supply: Our generating facilities are strategically located close to energy hubs that help reduce fuel supply costs. Our Colorado and Wyoming gas-fired generating facilities are located close to major natural gas energy hubs that provide trading liquidity and transparent pricing. Due to their location in the resource rich areas of Colorado and Wyoming, natural gas supply to fuel our gas-fired generation can be sourced at competitive prices. Our only coal-fired power plants, all located at the Gillette energy complex in northeastern Wyoming, are supplied by our adjacent coal mine. We operate and own majority interests in four of the five power plants and own 20% of the fifth power plant. The small coal mine provides approximately 3.5 million tons of low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our power plants when compared to alternatives. Nearly all the mine’s production is sold to these on-site generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck.
Supporting the Energy Transition by proactively integrating alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities of 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are based on existing technology and computed from 2005 baseline levels of GHG emissions intensity for our electric operations and natural gas distribution system. Since 2005, we have reduced GHG emissions intensity from our Gas Utilities by more than 33% and achieved a 30% reduction from our Electric Utilities (an additional 5% reduction since announcing our goal in 2020 for our Electric Utilities). Additionally, our Electric Utilities have reduced nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Our electric utility in Colorado has achieved a nearly 50% reduction in GHG emissions since 2005 and is on track to reach the State of Colorado’s 80% carbon reduction goal by 2030. Our goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This keeps our customers at the forefront of our decision-making, which is central to our values.
More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest:
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•We created the Renewable Ready program for South Dakota and Wyoming customers. In support of this program, we created and received approvals for new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmental customer requests for renewable energy resources. To meet the renewable energy commitments under the new tariffs, on November 30, 2020, we completed construction and placed into service the Corriedale wind project, a 52.5 MW wind energy project near Cheyenne, Wyoming.
•In June 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. The IRP outlines a range of options for the two electric utilities over a 20-year planning horizon to meet long-term forecasted energy needs while strengthening reliability and resiliency of the grid. The analysis focused on the least-cost resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving the Company’s generation emissions reduction goals. The IRP’s preferred options for the near-term planning period through 2026 propose the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 20 MW of battery storage.
Many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting GHG emission reduction targets. Federal legislation for renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely drive the need for significant investment in our Electric Utilities and Gas Utilities segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility we are responsible for providing safe, reliable and cost-effective sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with standards and regulations that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.
Explore opportunities as an energy solutions provider. Another strategic initiative is to grow our business through creative energy solutions with new customers and partnerships. We see value creation by recruiting new customers and expanding existing partnerships with data centers, crypto miners and other blockchain opportunities; exploring energy markets such as RTOs; and expanding our transmission capabilities. As an example, we have supported enabling legislation in Wyoming for the growing blockchain and digital currency businesses while implementing our own Blockchain Interruptible Service Tariff to serve these customers. We are also re-focusing on our product and services offerings to our natural gas customers.
Additionally, we are pursuing two important initiatives in the form of sustainable energy solutions for electric vehicles and renewable natural gas. These two programs support our near-term sustainable strategy and contribute to the achievement of our aspirational greenhouse gas emissions reduction goals.
•Electric Vehicles (EV): We expect EV market share to increase over the next one to three years, commensurate with a significant uptick in vehicle range and product offerings and marked decrease in EV purchase prices. In addition to future load growth opportunities, we will investigate behind-the-meter solutions for customers. In January 2022, the CPUC approved a transportation electrification plan for Colorado Electric including the implementation of EV and charger rebates and EV rates.
•Renewable Natural Gas (RNG): Our teams are developing RNG/carbon offset offerings for our retail customers, evaluating multiple RNG investment opportunities and exploring value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with several projects actively injecting RNG into our natural gas system.
Execute disciplined capital allocation and explore small strategic opportunities. We are planning a disciplined capital investment program of approximately $600 million annually over the next two years to improve our cash flows and reduce our debt to total capitalization ratio. By carefully managing capital, we plan to continue to strengthen our balance sheet and enhance our liquidity. With this goal in mind, we will continue to evaluate smaller scale acquisitions of private utility infrastructure systems and small municipal systems that can be easily incorporated into our existing utility systems.
Deliver a competitive total return to investors and maintain an investment grade credit rating. We are proud of our track record of annual dividend increases for shareholders. 2021 represented our 51st consecutive year of increasing dividends. In January 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend of $2.38 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.
We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings-accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating.
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Recent Developments
Winter Storm Uri
In February 2021, a prolonged period of historic cold temperatures across the central United States covered all of our Utilities’ service territories, caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, we incurred significant incremental natural gas and fuel costs.
On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and to meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. Proceeds from the August 26, 2021 debt transaction were used to repay amounts outstanding under this term loan. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.
During the second quarter, our Utilities submitted cost recovery applications with the utility commissions in our state jurisdictions to recover incremental costs associated with Winter Storm Uri. To date, several of our Utilities have received interim or final Commission Orders and have begun recovering costs from customers. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information on our regulatory activity.
COVID-19 Pandemic
For the year ended December 31, 2021, we did not experience significant impacts to our financial results, liquidity or operational activities due to COVID-19. We continue to monitor loads, customers’ ability to pay, the potential for supply chain disruption or inflation that may impact our capital and maintenance project plans, the availability of third-party resources to execute our business plans and the capital markets to ensure we have the liquidity necessary to support our financial needs. State Orders lifting temporarily suspended disconnections have been issued in all of our jurisdictions.
As we look forward, our operating results could be affected by COVID-19 as discussed in detail in our Risk Factors.
Business Segment Highlights and Corporate Activity
Electric Utilities
•On January 26, 2022, Colorado Electric agreed to join SPP’s Western Energy Imbalance Service Market. Colorado Electric, PRPA, and the Colorado subsidiary of Xcel Energy Inc. will join the market in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market to dispatch energy at lower costs.
•On January 5, 2022, South Dakota Electric and Wyoming Electric set new winter peak loads. This is the fourth new winter peak for Wyoming Electric since 2015. Wyoming Electric’s new winter peak load of 253 MW surpasses the previous peak of 247 MW set in December 2019. South Dakota Electric’s new winter peak of 327 MW surpasses the previous winter peak of 326 MW set in February 2021.
•In November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. See Key Elements of our Business Strategy above for further information.
•On October 5, 2021, our Electric Utilities and several other utilities in the western United States formed the Western Markets Exploratory Group to research the potential for an organized wholesale market in the western interconnect, including expanding transmission systems and other grid-related services. The group plans to identify market solutions that can help achieve carbon reduction goals while supporting reliable, cost-effective services for customers.
•On September 19, 2021, Wygen I experienced an unplanned outage that continued until mid-December 2021. For the year ended December 31, 2021, the outage had an $11 million negative impact to Operating income. We are currently assessing insurance recovery opportunities.
•On August 24, 2021, Wyoming Electric issued a request for proposals under its Blockchain Interruptible Service tariff. We have narrowed the bidder’s list and selected finalists for contract negotiations.
•On July 28, 2021, Wyoming Electric set a new all-time and summer peak load of 274 MW, exceeding the previous peak of 271 MW set in July 2020.
•On July 27, 2021, South Dakota Electric set a new all-time and summer peak load of 397 MW, exceeding the previous peak of 378 MW set in August 2020.
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•On June 30, 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. See Key Elements of our Business Strategy above for further information.
•On February 19, 2021, Colorado Electric entered into a PPA with TC Colorado Solar, LLC (TC Solar) to purchase up to 200 MW of renewable energy upon construction of a new solar facility, to be owned by TC Solar. On January 31, 2022, TC Solar provided termination notice of the PPA to Colorado Electric. Colorado Electric has disputed TC Solar’s right to termination and pursuant to the agreement, has initiated discussions with TC Solar.
Gas Utilities
•See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent regulatory activity for our Gas Utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska.
Corporate and Other
•On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% 3-year senior unsecured notes due August 23, 2024. The proceeds from the offering were used to repay amounts outstanding under our term loan entered into on February 24, 2021. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.
•On July 19, 2021, we amended and restated our corporate Revolving Credit Facility. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.
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Results of Operations
Our discussion and analysis for the year ended December 31, 2021 compared to 2020 as well as discussion and analysis of the results of operations for the year ended December 31, 2020 compared to 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2020 compared to 2019, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on February 26, 2021.
In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to the allocation of resources. Comparative periods presented reflect this change. See further segment information in Note 16 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Segment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.
Consolidated Summary and Overview
For the Years Ended December 31,
(in thousands, except per share amounts)
Operating income (loss):
Net income attributable to non-controlling interest (14,516) (15,155) (14,012)
Total earnings per share of common stock, Diluted $ 3.74 $ 3.65 $ 3.28
2021 Compared to 2020
The variance to the prior year included the following:
•Electric Utilities’ operating income decreased $8.3 million primarily due to Colorado Electric’s TCJA-related bill credits to customers (which is offset by reduced tax expense), unfavorable impacts from an unplanned outage at Wygen I and higher depreciation as a result of additional plant placed in service, partially offset by increased power marketing and wholesale revenues, increased rider revenues, increased commercial and industrial demand, a prior year expense related to the early retirement of certain non-regulated generation assets, residential customer growth and increased usage, and prior year COVID-19 impacts;
•Gas Utilities’ operating income decreased $4.7 million primarily due to Winter Storm Uri costs incurred by Black Hills Energy Services, lower heating demand from milder weather (primarily in the fourth quarter of 2021), Nebraska Gas TCJA-related bill credits to customers and higher operating expenses partially offset by new rates and customer growth;
•Corporate and Other expenses increased $5.8 million primarily due to higher employee costs driven by a prior year favorable true-up;
•Interest expense increased $8.9 million primarily due to higher debt balances partially offset by lower rates;
•A prior year $6.9 million pre-tax non-cash impairment in 2020 of our investment in equity securities of a privately held oil and gas company;
•Other income increased $3.7 million primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance; and
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•Income tax expense decreased $26 million primarily due to lower pre-tax income and a lower effective tax rate driven primarily by tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits (which is offset by reduced revenue), flow-through tax benefits related to repairs and gain deferral and increased tax benefits from federal production tax credits associated with new wind assets.
2020 Compared to 2019
The variance to the prior year included the following:
•COVID-19 related impacts to consolidated results included $3.6 million of lower Electric and Gas Utility margin driven primarily by lower volumes and waived customer late payment fees, $2.6 million of costs due to sequestration of essential employees and $3.3 million of additional bad debt expense which were partially offset by $3.8 million of lower travel, training, and outside services related expenses;
•Electric Utilities’ operating income decreased $6.7 million due to higher depreciation and amortization expense as a result of additional plant placed in service including new wind assets, expense from the early retirement of certain non-regulated assets, lower commercial and industrial demand and COVID-19 impacts partially offset by increased revenue from our non-regulated power generation and mining businesses, benefits from the release of TCJA revenue reserves and increased rider revenues;
•Gas Utilities’ operating income increased $26 million primarily due to new customer rates in Wyoming and Nebraska and increased rider revenues, customer growth, mark-to-market gains on non-utility natural gas commodity contracts and a 2019 amortization of excess deferred income taxes partially offset by higher depreciation and amortization expense as a result of additional plant placed in service, COVID-19 impacts and unfavorable weather;
•Corporate and Other expenses decreased $3.0 million primarily due to an unallocated favorable true-up of employee costs;
•A $6.9 million pre-tax non-cash impairment in 2020 of our investment in equity securities of a privately held oil and gas company compared to a similar $20 million impairment in 2019;
•Interest expense increased $5.8 million primarily due to higher debt balances partially offset by lower rates;
•Other expense decreased $3.4 million due to the 2019 expensing of $5.4 million of development costs related to projects we no longer intend to construct partially offset by increased pension non-service costs in 2020; and
•Income tax expense increased $3.3 million primarily due to higher pre-tax income partially offset by a lower effective tax rate.
Segment Operating Results
A discussion of operating results from our business segments follows.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Electric and Gas Utility margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Electric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses, depreciation and amortization expenses, and property and production taxes from the measure.
Electric Utility margin is calculated as operating revenue less cost of fuel and purchased power. Gas Utility margin is calculated as operating revenue less cost of natural gas sold. Our Electric and Gas Utility margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact Electric and Gas Utility margin as a percentage of revenue, they only impact total Electric and Gas Utility margin if the costs cannot be passed through to our customers.
Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
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Electric Utilities
Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands):
Revenue:
Fuel and Purchased Power:
2021 Compared to 2020
Electric Utility margin decreased over the prior year as a result of:
(in millions)
TCJA-related bill credits (a) $ (10.2)
Wygen I unplanned outage (8.5)
Prior year release of TCJA revenue reserves (2.2)
Weather (1.2)
Winter Storm Uri impacts (b) (0.4)
Power marketing and wholesale 5.9
Residential customer growth and increased usage per customer 5.1
Rider recovery 4.2
Prior year COVID-19 impacts 1.8
Other (0.5)
Total decrease in Electric Utility margin $ (6.0)
____________________
(a) In February and April 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income.
(b) As a result of Winter Storm Uri, our Electric Utilities incurred $2.1 million of incremental fuel costs that are not recoverable through our fuel cost recovery mechanisms which were mostly offset by $1.7 million of increased Electric Utility margin realized under Black Hills Wyoming’s Economy Energy PSA.
Operations and maintenance expense decreased primarily due to a $3.1 million prior year expense related to the early retirement of certain non-regulated generation assets, $2.7 million of lower overburden, production taxes and other operating expenses on decreased mining volumes, $2.0 million of prior year COVID-19 expenses and $1.7 million of decreased bad debt expense associated with lower expected credit losses, partially offset by $2.7 million of increased expenses related to planned and unplanned outages at our generation facilities and $1.0 million of increased operating expenses from new wind assets.
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Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
2020 Compared to 2019
Electric Utility margin increased in 2020 over 2019 as a result of:
(in millions)
Integrated Generation (a) $ 3.3
Rider recovery 2.3
Release of TCJA revenue reserves (b) 2.2
Transmission services 1.4
Residential customer growth 0.9
Lower commercial and industrial demand (2.7)
COVID-19 impacts (c) (1.8)
Weather (0.3)
Total increase in Electric Utility margin $ 6.9
____________________
(a) Primarily driven by revenue from Busch Ranch II, which was placed in service in November 2019.
(b) In July 2020, regulatory proceedings resolved the last of the Company's open dockets seeking approval of its TCJA plans. As a result, the Company reversed certain TCJA-related liabilities, which resulted in an increase to Electric Utility margin of $2.2 million. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
(c) The impacts to Electric Utility margin from COVID-19 were primarily driven by reduced commercial volumes and waived customer late payment fees partially offset by higher residential usage.
Operations and maintenance expense increased primarily due to a $3.1 million expense related to the early retirement of certain non-regulated assets, $2.0 million of higher maintenance expense from new wind assets and $2.0 million of unfavorable net impacts from COVID-19 which included $2.6 million of expenses related to the sequestration of essential employees and $0.8 million of additional bad debt expense which were partially offset by $1.4 million of lower travel, training and outside services related expenses. Additionally, lower employee costs of $1.9 million were partially offset by $1.0 million of higher property taxes due to a higher asset base driven by capital expenditures.
Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.
Operating Statistics
Revenue (in thousands) Quantities Sold (MWh)
____________________
(a) Primarily related to transmission revenues from the Common Use System.
(b) Includes Integrated Generation and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.
(c) Includes company uses and line losses.
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Electric Revenue (in thousands) Quantities Sold (MWh)
For the year ended December 31,
Quantities Generated and Purchased by Fuel Type (MWh) 2021 2020 2019
Generated:
Purchased:
For the year ended December 31,
Generated:
Purchased:
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For the year ended December 31,
Heating Degree Days:
Cooling Degree Days:
____________________
(a) Degree days are calculated based on a weighted average of total customers by state.
For the year ended December 31,
Contracted generating facilities Availability by fuel type(a) 2021 2020 2019
Natural gas and diesel oil (c) 95.5% 84.6% 90.5%
____________________
(a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b) 2021 included planned outages at Neil Simpson II, Wygen II, and Wygen III and unplanned outages at Wygen I, Neil Simpson II and Wyodak Plant.
(c) 2020 included a planned outage at Cheyenne Prairie and unplanned outages at Pueblo Airport Generation and Lange CT. 2019 included planned outages at Neil Simpson CT and Lange CT.
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Gas Utilities
Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):
Revenue:
Cost of natural gas sold:
2021 Compared to 2020
Gas Utility margin increased over the prior year as a result of:
(in millions)
New rates $ 20.5
Carrying costs on Winter Storm Uri regulatory asset (a) 4.0
Increased transport and transmission 2.2
Prior year COVID-19 impacts 1.8
Mark-to-market on non-utility natural gas commodity contracts 0.9
Black Hills Energy Services Winter Storm Uri costs (b) (8.2)
Weather (6.8)
TCJA-related bill credits (c) (2.9)
Other (1.4)
Total increase in Gas Utility margin $ 10.1
____________________
(a) In certain jurisdictions, we have Commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense.
(b) Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri is not recoverable through a regulatory mechanism.
(c) In June 2021, Nebraska Gas delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income.
Operations and maintenance expense increased primarily due to $9.6 million of higher employee costs, $3.3 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures and $2.0 million of higher outside services expenses. The increase in expense was partially offset by $4.4 million of decreased bad debt expense associated with lower expected credit losses.
Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures partially offset by lower depreciation rates approved in the Nebraska Gas and Colorado Gas rate reviews.
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2020 Compared to 2019
Gas Utility margin increased in 2020 over 2019 as a result of:
(in millions)
New rates $ 25.4
Customer growth - distribution 5.6
Mark-to-market on non-utility natural gas commodity contracts 3.3
Amortization of excess deferred income taxes in 2019 2.6
Weather (1.8)
COVID-19 impacts (a) (1.8)
Total increase in Gas Utility margin $ 35.9
____________________
(a) The impacts to Gas Utility margin from COVID-19 were primarily driven by reduced volumes from certain transport customers and waived customer late payment fees.
Operations and maintenance expense increased primarily due to higher property taxes due to a higher asset base driven by capital expenditures. Lower employee costs were mostly offset by various other 2020 expenses. COVID-19 impacts to operations and maintenance expense included $2.5 million of additional bad debt expense which was partially offset by $2.4 million of lower travel, training, and outside services related expenses.
Depreciation and amortization increased primarily due to a higher asset base driven by capital expenditures.
Operating Statistics
Revenue (in thousands) Quantities Sold and Transported (Dth)
For the year ended December 31, For the year ended December 31,
____________________
(a) Includes Black Hills Energy Services and non-regulated services under the Service Guard Comfort Plan, Tech Services and HomeServe.
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Revenue (in thousands) Quantities Sold and Transported (Dth)
For the year ended December 31, For the year ended December 31,
For the year ended December 31,
____________________
(a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins.
(b) Heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.
Corporate and Other
Corporate and Other operating results for the years ended December 31 were as follows (in thousands):
2021 Compared to 2020
The variance in Operating income (loss) was primarily due to a prior year favorable true-up of employee costs which was allocated to our subsidiaries in the current year. This allocation was offset in our business segments and had no impact to consolidated results.
2020 Compared to 2019
The variance in Operating income (loss) was primarily due to a 2020 unallocated favorable true-up of employee costs.
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Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)
2021 Compared to 2020
Interest expense, net
The increase in Interest expense, net was due to higher debt balances driven by the August 2021 senior unsecured notes and February 2021 term loan, partially offset by lower interest rates.
Impairment of investment
In the prior year, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company. The impairment was triggered by continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company.
Other income (expense), net
The variance in Other income (expense), net was primarily due to lower non-service pension costs driven by a lower discount rate, lower costs for our non-qualified benefit plans which were driven by market performance and recognition of death benefits from Company-owned life insurance.
Income tax benefit (expense)
For the year ended December 31, 2021, the effective tax rate was 2.8% compared to 11.9% in 2020. The lower effective tax rate is primarily due to $10 million of increased tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits to customers (which is offset by reduced revenue), $6.6 million of increased flow-through tax benefits related to repairs and gain deferral, $4.6 million of increased tax benefits from federal production tax credits associated with new wind assets, $2.9 million of increased tax benefits from amortization of excess deferred income taxes and $2.6 million from various statutory rate changes. These current year tax benefits were greater than prior year tax benefits from one-time research and development tax credits and the reversal of accrued excess deferred income taxes as part of resolving the last of the Company’s open dockets seeking approval of its TCJA plans. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
2020 Compared to 2019
Interest expense, net
The increase in Interest expense, net was driven by higher debt balances partially offset by lower interest rates.
Impairment of investment
In 2020, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company, compared to a $20 million write-down in 2019. The impairments in both years were triggered by continued adverse natural gas prices and liquidity concerns at the privately held oil and gas company.
Other income (expense), net
The variance in Other income (expense), net was primarily due to the 2019 expensing of $5.4 million of development costs related to projects we no longer intend to construct which was partially offset by higher 2020 non-service defined benefit plan costs primarily driven by lower discount rates.
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Income tax benefit (expense)
For the year ended December 31, 2020, the effective tax rate was 11.9% compared to 12.2% in 2019. The lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and one-time research and development tax credits partially offset by a 2019 tax benefit from a federal tax loss carry-back claim including interest. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
Liquidity and Capital Resources
OVERVIEW
Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our operating activities, five-year Revolving Credit Facility, CP Program, ATM and ability to access the public and private capital markets through debt and equity securities offerings when necessary. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.
We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption, during periods of high natural gas prices, and during the construction season which typically peaks in spring and summer.
We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
In response to Winter Storm Uri, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Recent Developments section above.
The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):
Cash and cash equivalents $ 8,921 $ 6,356
Restricted cash and equivalents $ 4,889 $ 4,383
Current maturities of long-term debt $ — $ 8,436
Ratios
Long-term debt ratio 60 % 58 %
Total debt ratio 62 % 60 %
____________________
(a) Carrying value of long-term debt is net of deferred financing costs.
CASH FLOW ACTIVITIES
The following table summarizes our cash flows for the years ended December 31 (in thousands):
Cash provided by (used in)
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2021 Compared to 2020
Operating Activities:
Net cash used in operating activities was $606 million higher than in 2020. The variance to the prior year was primarily attributable to:
•Cash earnings (income from continuing operations plus non-cash adjustments) were $21 million lower than prior year driven primarily by negative impacts from the unplanned outage at Wygen I, lower Electric and Gas Utility margin from Winter Storm Uri and unfavorable weather, higher operating expenses and higher interest expenses;
•Net outflows from changes in certain operating assets and liabilities were $593 million higher than prior year, primarily attributable to:
•Cash outflows increased by approximately $508 million primarily as a result of changes in our regulatory assets and liabilities primarily driven by incremental fuel, purchased power and natural gas costs due to Winter Storm Uri;
•Cash inflows decreased by approximately $71 million primarily as a result of changes in accounts receivable and other current assets driven by decreased collections of accounts receivable and increased purchases of natural gas in storage;
•Cash inflows decreased by approximately $14 million as a result of changes in accounts payable and other current liabilities driven by payment timing related to payroll taxes;
•Cash outflows decreased by $13 million due to pension contributions made in the prior year; and
•Cash inflows decreased $4.5 million for other operating activities.
Investing Activities:
Net cash used in investing activities was $97 million lower than in 2020. This variance to the prior year was primarily attributable to:
•Capital expenditures of approximately $677 million in 2021 compared to $767 million in 2020. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas Utilities segments and the prior year Corriedale wind project at our Electric Utilities segment; and
•Cash inflows increased $7.5 million for other investing activities primarily driven by the sales of transmission assets and facilities, none of which were individually significant.
Financing Activities:
Net cash provided by financing activities was $515 million higher than in 2020. This variance to the prior year was primarily attributable to:
•Cash inflows increased $502 million due to long and short-term borrowings in excess of repayments;
•Cash inflows increased $20 million due to higher issuances of common stock;
•Cash outflows increased $10 million due to increased dividends paid on common stock; and
•Cash outflows decreased by $3.0 million for other financing activities.
CAPITAL RESOURCES
Short-term Debt
Revolving Credit Facility and CP Program
We have a $750 million Revolving Credit Facility that matures on July 19, 2026 with two one-year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment. We also have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million.
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The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.
The Revolving Credit Facility contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to 1) make timely payments of debt obligations; or 2) triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permit the acceleration of debt maturities or mandatory debt prepayment.
Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):
Current Short-term borrowings at Letters of Credit (a) at Available Capacity at
____________________
(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit. For more information on these letters of credit, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
The weighted average interest rate on short-term borrowings at December 31, 2021 was 0.30%. Short-term borrowing activity for the year ended December 31, 2021 was:
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances) $ 440
Average amount outstanding (based on daily outstanding balances) $ 258
Weighted average interest rate 0.22 %
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our Revolving Credit Facility and CP Program.
Term Loan
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information related to our term loan.
Utility Money Pool
As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may, at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based rates. While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
Long-term Debt
Our Long-term debt and associated interest payments due by year are shown below (in thousands). For more information on our long-term debt, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Payments Due by Period
____________________
(a)Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2021.
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Covenant Requirements
The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of December 31, 2021. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Equity
Shelf Registration
We have a shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2023. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2021, we had approximately 65 million shares of common stock outstanding and no shares of preferred stock outstanding.
ATM
Our ATM allows us to sell shares of our common stock with an aggregate value of up to $400 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. During the twelve months ended December 31, 2021, we issued a total of 1,812,197 shares of common stock under the ATM for $119 million, net of $1.1 million in issuance costs.
For additional information regarding equity, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Future Financing Plans
We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2022, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of common stock under the ATM.
CREDIT RATINGS
Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. We note that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2021:
Rating Agency Senior Unsecured Rating Outlook
S&P (a) BBB+ Stable
Moody’s (b) Baa2 Stable
Fitch (c) BBB+ Stable
____________________
(a) On October 20, 2021, S&P reported BBB+ rating and maintained a Stable outlook.
(b) On December 20, 2021, Moody’s reported Baa2 rating and maintained a Stable outlook.
(c) On September 17, 2021, Fitch reported BBB+ rating and maintained a Stable outlook.
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Certain fees and interest rates under our Revolving Credit Facility are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgrades our senior unsecured debt, we will be required to pay higher fees and interest rates under our Revolving Credit Facility.
The following table represents the credit ratings of South Dakota Electric at December 31, 2021:
Rating Agency Senior Secured Rating
S&P (a) A
Fitch (b) A
____________________
(a) On July 1, 2021, S&P reported A rating.
(b) On September 17, 2021, Fitch reported A rating.
We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.
CAPITAL REQUIREMENTS
Capital Expenditures
Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity of our system and is included in utility rate base and eligible for recovery from our utility customers with regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.
Our capital expenditures for the three years ended December 31 were as follows (in thousands):
Capital Expenditures By Segment (a) :
____________________
(a) Includes accruals for property, plant and equipment as disclosed as supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements in this Annual Report on Form 10-K.
Repayments of Indebtedness
For information relating to repayments of our short- and long-term debt and associated interest payments, see the Capital Resources section above and Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Unconditional Purchase Obligations
We have unconditional purchase obligations which include the energy and capacity costs associated with our PPAs, transmission services agreements, and natural gas capacity, transportation and storage agreements. Additionally, our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. For additional information. see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Defined Benefit Pension Plan
We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The unfunded status of the Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the plan is $20 million as of December 31, 2021, compared to $40 million as of December 31, 2020. While we do not have required contributions, we expect to make $3.9 million in contributions to our Pension Plan in 2022. See further information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.
Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
On January 26, 2022, our Board of Directors declared a quarterly dividend of $0.595 per share, equivalent to an annual dividend rate of $2.38 per share. The table below provides our dividends paid (in thousands), dividend payout ratio and dividends paid per share for the three years ended December 31:
Dividend Payout Ratio 61 % 60 % 63 %
Our three-year compound annualized dividend growth rate was 5.9%.
Collateral Requirements
Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At December 31, 2021, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. The cash collateral we were required to post at December 31, 2021 was not material.
Guarantees
We provide various guarantees, which represent off-balance sheet commitments, supporting certain of our subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Critical Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. We continue to closely monitor the impacts of COVID-19 and Winter Storm Uri on our critical accounting estimates including, but not limited to, collectibility of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, valuation of pension assets and liabilities and contingent liabilities. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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Regulation
Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.
Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state regulatory commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs.
As of December 31, 2021 and 2020, we had total regulatory assets of $797 million and $278 million, respectively, and total regulatory liabilities of $503 million and $533 million, respectively. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.
Goodwill
We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns with our financial planning process.
Accounting standards for testing goodwill for impairment require the application of either a qualitative or quantitative assessment to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. Under either the qualitative or quantitative assessment, the estimated fair value of a reporting unit is compared with its carrying amount, including goodwill. If the carrying amount exceeds fair value, then an impairment loss would be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit.
Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which the Chief Operating Decision Maker (CODM) regularly reviews the operating results. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the range of 4.9% to 5.1% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2021. Although 1.75% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.
The estimates and assumptions used in the impairment assessments are based on available market information and we believe they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. For the years ended December 31, 2021, 2020, and 2019, there were no impairment losses recorded. At December 31, 2021, the fair value substantially exceeded the carrying value at all reporting units.
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Pension and Other Postretirement Benefits
As described in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A VEBA trust for the funded portion of the post-retirement healthcare plan has also been established.
Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.
The 2022 pension benefit cost for our non-contributory funded pension plan is expected to be $2.2 million compared to $0.8 million in 2021. The increase in the expected 2022 pension benefit cost is driven primarily by lower expected asset returns and a higher discount rate.
The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:
December 31,
Pension
Expected return on assets +/- 0.5 N/A (2,180)/2,180
OPEB
Expected return on assets +/- 0.5 N/A (37)/37
____________________
(a) Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans.
(b) Impact on service cost, interest cost and amortization of gains or losses.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.
The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be made in the period such determination was made. These adjustments may increase or decrease earnings. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.
See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.
Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed, but not limited to, the following market risks:
•Commodity price risk associated with our retail natural gas services, wholesale electric power marketing activities and fuel procurement for several of our gas-fired generation assets. Market fluctuations may occur due to unpredictable factors such as weather (Winter Storm Uri), market speculation, inflation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and
•Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.
Credit risk is associated with financial loss resulting from non-performance of contractual obligations by a counterparty.
To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at least quarterly and as necessary, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.
Commodity Price Risk
Electric and Gas Utilities
Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to reflect billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota and Wyoming, we have ECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that adjust natural gas rates when our natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic prudence reviews by the state regulatory commissions.
The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state regulatory commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations.
For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income. See additional information in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Wholesale Power
We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments and do not qualify for the normal purchase and normal sales exception for derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income.
A potential risk related to wholesale power sales is the price risk arising from the sale of power that exceeds our generating capacity. These potential short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.
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Black Hills Energy Services
We buy and sell natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with fixed price forward contracts to supply gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings.
At December 31, 2021 and 2020, a 10% change in market prices for our derivative instruments would not materially impact pre-tax income, the fair values of our derivative assets and liabilities, or OCI.
See additional commodity risk and derivative information in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Interest Rate Risk
Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and anticipated debt refinancings. At December 31, 2021, we had no interest rate swaps in place. Further details of past swap agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
At December 31, 2021, 91% of our debt is fixed rate debt, which limits our exposure to variable interest rate fluctuations. A hypothetical 100 basis point increase in the benchmark rate on our variable rate debt would have increased annual pretax interest expense by approximately $2.7 million and $2.1 million for the years ended December 31, 2021 and 2020, respectively. See Note 8 for further information on cash amounts outstanding under short- and long-term variable rate borrowings.
We are subject to interest rate risk associated with our pension and post-retirement benefit obligations. Changes in interest rates impact the liabilities associated with these benefit plans as well as the amount of income or expense recognized for these plans. Declines in the value of the plan assets could diminish the funded status of the pension plans and potentially increase the requirements to make cash contributions to these plans. See additional information in Critical Accounting Estimates in Item 7 and Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Credit Risk
We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified. Our credit exposure at December 31, 2021 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.
See more information in Notes 1 and 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.