
•	~~Black Hills Wyoming’s economy energy PPA and other ancillary agreements are discussed in~~ ~~Note 19~~ Table of Contents ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~

~~Operating and Maintenance Services Agreement~~

◦

In conjunction with the sale of a noncontrolling interest in 2016, an operating and maintenance services agreement was entered into between Black Hills Electric Generation and Black Hills Colorado IPP. This agreement sets forth the obligations and responsibilities of Black Hills Electric Generation as the operator of the generating facility owned by Black Hills Colorado IPP. This agreement became effective on the date of the noncontrolling interest purchase and remains effective as long as the operator or one of its affiliates is responsible for managing the generating facilities in accordance with the noncontrolling interest agreement, or until termination by owner or operator.

~~Shared Services Agreements~~


◦	~~South Dakota Electric, Wyoming Electric and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity is charged for the use of assets by the affiliate entity.~~


◦	~~Black Hills Colorado IPP and Colorado Electric are parties to a facility fee agreement, whereby Colorado Electric charges Black Hills Colorado IPP for the use of Colorado Electric’s assets.~~


◦	Black Hills Colorado IPP, Wyoming Electric and South Dakota Electric are parties to a Spare Turbine Use Agreement, whereby Black Hills Colorado IPP charges South Dakota Electric and Wyoming Electric a monthly fee for the availability of a spare turbine to support the operation of Cheyenne Prairie.


◦	~~Black Hills Colorado IPP and Black Hills Wyoming receive certain staffing and management services from BHSC.~~


•	~~Jointly owned facilities agreements are discussed in~~ ~~Note 4~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~

Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess.

With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity and foster competition within the wholesale electricity markets. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for ~~independent power producers~~IPPs in some regions. To date, these initiatives have not had a material impact on our Power Generation segment.

The Energy Policy Act of ~~1992.~~ ~~The passage of the Energy Policy~~1992 and Public Utility Holding Company Act of ~~1992 encouraged independent power production by providing certain exemptions from regulation for EWGs. EWGs are~~2005 (PUHCA 2005). PUHCA 2005 reiterated the definition and benefits of Exempt Wholesale Generator (EWG) status. Under PUHCA 2005, an EWG is an entity or generator engaged, directly or indirectly through one or more affiliates, exclusively in the business of owning, or operating or both owning and operating all or part of one or more eligible ~~power~~ facilities and selling electric energy at wholesale. Though EWGs are public utilities within the definition set forth in the Federal Power Act and are subject to FERC regulation ~~including rate regulation. We own five EWGs:~~of rates and charges, they are exempt from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with three EWGs, Wygen I, Pueblo Airport ~~Generation, Busch Ranch I, Busch Ranch II~~Generating and Top of Iowa. ~~Our EWGs were~~Each of these three EWG’s have been granted market-based rate ~~authority, which allows FERC to waive certain accounting, record-keeping~~authority.

Operating statistics. See a summary of key operating statistics in the Power Generation segment operating results within Management’s Discussion and ~~reporting requirements imposed~~Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on ~~public utilities with cost-based rates.~~Form 10-K.

Mining ~~Segment~~

Our Mining segment operates a single coal mine through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC mine, which we acquired in 1956 from Homestake Mining Company, is located in the Powder River ~~Basin in eastern Wyoming.~~Basin. We produced approximately 3.7 million tons of coal in ~~2019.~~2020.

During our surface mining operations, we strip and store the topsoil. We then remove the overburden (earth and rock covering the coal) with heavy equipment. Removal of the overburden typically requires drilling and blasting. Once the coal is exposed, we drill, fracture and systematically remove it, using front-end loaders and conveyors to transport the coal to the mine-mouth generating facilities. We reclaim disturbed areas as part of our normal mining activities by back-filling the pit with overburden removed during the mining process. Once we have replaced the overburden and topsoil, we reestablish vegetation and plant life in accordance with our approved post-mining topography plan.

In a basin characterized by thick coal seams, our overburden ratio, a comparison of the cubic yards of dirt removed to a ton of coal uncovered, has ~~in recent years~~ trended ~~upwards. The~~upwards over the last fifteen years. However, the overburden ratio at December 31, ~~2019~~2020 was 2.17 which decreased from 2.30 ~~which increased from~~in the prior year as we ~~continued mining~~mined in areas with ~~higher~~lower overburden. We expect our stripping ratio to beincrease to approximately ~~2.18~~2.27 by the end of ~~2020~~2021 as we mine in areas with ~~comparable~~higher overburden.

Mining rights to the reserves are based on three federal leases and one state lease. The federal leases expire between March 31, 2021 and September 30, 2025 and the state lease expires on August 1, 2023. The duration of the leases varies; however, the lease terms generally are extended to the exhaustion of economically recoverable reserves, as long as active mining continues. The federal lease expiring March 31, 2021 relates to an area we are no longer mining and will not be renewed. The Biden Administration recently issued an executive order that suspends new oil and gas leases on federal lands and eliminates fossil fuel subsidies. However, this moratorium does not apply to federal mining leases and we have not received federal subsidies.

We pay federal and state royalties of 12.5% of the selling price of all coal. As of December 31, ~~2019,~~2020, we estimated our recoverable reserves to be approximately ~~185~~182 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable reserve life is equal to approximately 5049 years at the current production levels. Our recoverable reserve estimates are periodically updated to reflect past production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable reserves include reserves that can be economically and legally extracted at the time of their determination.

Substantially all of the mine’s production is currently sold under contracts to:

•South Dakota Electric for use at the 90 MW Neil Simpson II plant to which we sell approximately 500,000 tons each year. This contract is for the life of the plant;

•Wyoming Electric for use at the 95 MW Wygen II plant to which we sell approximately 550,000 tons each year. This contract is for the life of the plant;

•

The 362 MW Wyodak Plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 375,000 tons per year for its 20% share of the power plant, subject to adjustments for planned outages.

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•The 362 MW Wyodak Plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons each year, subject to adjustments for planned outages and other contract terms. This contract expires December 31, 2022 and negotiations to extend the contract are ongoing. South Dakota Electric is also obligated to purchase a minimum of 375,000 tons per year for its 20% share of the power plant, subject to adjustments for planned outages and other contract terms;

•~~and negotiations are underway to extend the contract~~;

The 110 MW Wygen III power plant jointly owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons each ~~year. This contract expires June 1, 2060;~~year;

•The 90 MW Wygen I power plant jointly owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons each ~~year. This contract expires June 30, 2038;~~year; and

•Certain regional industrial customers served by truck to which we sell a total of approximately ~~150,000~~300,000 tons each year. These contracts have terms of one to five years.

Our Mining segment sells coal to South Dakota Electric and Wyoming Electric for all of their requirements under cost-based agreements that regulate earnings from these affiliate sales to a specified return on our mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above Moody’s A-Rated Utility Bond Index applied to our Mining investment base. South Dakota Electric made a commitment to the SDPUC, the WPSC and the City of Gillette that coal for South Dakota Electric’s operating plants would be furnished and priced as provided by that agreement for the life of the Neil Simpson II plant and through June 1, 2060, for Wygen III. The agreement with Wyoming Electric provides coal for the life of the Wygen II plant.

The price of unprocessed coal sold to PacifiCorp for the Wyodak Plant is determined by the supply agreement described above. The agreement included a price adjustment in 2019. The price adjustment essentially allowed us to retain the full economic advantage of the mine’s location adjacent to the plant. The price adjustment was based on market price plus considerations for the avoided costs of rail transportation and an unloading facility, which PacifiCorp would have to incur if it purchased from another mine. In addition, the agreement also provided for the monthly escalation of price based on an escalation factor.

In October 2019, negotiations were completed for the price re-opener in the contract with the Wyodak Plant. The new price was

reset at $17.94 per ton effective July 1, 2019, compared to the prior contract price of $18.25 per ton. The current contract price is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of an unloading facility (approximately 30% of current price); and 3) a rolling 12-month average of the Coal Daily spot market price of 8,400 Btu Powder River Basin coal (approximately 50% of current price).

WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement ~~using~~through June 30, 2038. Currently, this agreement uses a base price that includes price escalators and quality adjustments ~~through June 30, 2038~~ and includes actual cost per ton plus a margin equal to the yield for Moody’s A-Rated Utility Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. ~~The agreement stipulates that WRDC will supply coal to~~Effective January 1, 2022, in conjunction with the ~~90 MW~~new Wygen I ~~plant through June 30, 2038.~~60 MW PPA, WRDC’s current coal supply agreement will be revised using pricing that will be cost-based to regulate earnings to a specified return on the cost-depreciated investment base. For additional information regarding the new Wygen I 60 MW PPA, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Competition. Our strategy is to sell the majority of our production to on-site, mine-mouth generation facilities under long-term supply contracts. Historically, any off-site sales have been to consumers within close proximity to the WRDC mine. Rail transport market opportunities for WRDC are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC mine is served by only one railroad, resulting in less competitive transportation rates. ~~Management continues to explore the limited market opportunities for our product through truck transport.~~

Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental ~~considerations~~ and availability considerations affect the overall demand for coal as a fuel.

Environmental Matters. We are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. See Environmental Matters section for further information.

Mine Reclamation. Reclamation is ~~required~~completed during production and after mining has ~~been completed.~~finished. Under applicable law, we must submit applications to, and receive approval from, the ~~WDEQ~~Wyoming Department of Environmental Quality for any mining and reclamation plans that provide for orderly mining, reclamation and restoration of the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC mine is permitted to operate under a five-year mining permit issued by the State of Wyoming. In 2016, that five-year permit was ~~re-issued.~~re-issued and we are currently in the process of renewing this permit. Based on extensive reclamation studies, we have accrued approximately ~~$14~~$13 million for reclamation costs as of December 31, ~~2019.~~2020. See additional information in Note 87 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K.

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Operating statistics. See a summary of key operating statistics in the Mining segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

Environmental Matters

In November 2020, we announced clean energy goals to reduce GHG emissions that are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. See more information in Key Elements of our Business Strategy within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

Environmental Management System (EMS). We operate an EMS that is composed of environmental policies and procedures, voluntary initiatives, objectives and annual targets, operational controls, training, a sophisticated task scheduling/tracking and document control system, and a continuous improvement process. The program attained Colorado’s highest level in their Environmental Leadership Program (Gold Level status in 2014) and has continued this status through 2020.

Methane Rules (Greenhouse Gas Emissions).. The EPA and the State of Colorado have implemented strict regulatory requirements on hydrocarbon and methane emissions associated with natural gas gathering and transmission systems. ~~The BLM repealed similar hydrocarbon and methane emissions reductions it previously established under the Methane Rule (Venting and Flaring rule).~~Presently, we have ~~four~~ facilities in our ~~Colorado~~ natural gas transmission operations affected by the ~~hydrocarbon and~~ methane reduction rules.

Our operations are ~~currently~~ in compliance with both EPA and State of Colorado rules. Future modifications to our gathering and transmissions systems are anticipated to trigger EPA methane ~~rules.~~ rules that we will adhere to. We developed a~~We plan to develop a~~ corporate-wide methane control strategy to address GHG emissions. As a proactive measure in reducing methane emissions asbeyond current regulatory requirements, we ~~anticipate this will be~~have entered into the EPA’s Methane Challenge Program. This is a ~~requirement in future rule-making efforts.~~

~~Water Issues.~~ Our facilities are subject to a variety of state and federal regulations governing existing and potential water/ wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under the Clean Water Act and govern overall water/wastewater discharges through EPA’s surface water discharge and storm water permits. All of our facilities that are required to have such permits have those permits in place and are in compliance with discharge limitations and plan implementation requirements. The EPA proposed effluent limitation guidelines and standards on June 7, 2013, and published the final rule on November 3, 2015. In 2017,voluntary program founded by the EPA ~~postponed the implementation of the rule~~in collaboration with oil and ~~set a timeline in 2018~~natural gas companies that recognizes companies that make specific and transparent commitments to revise the rule. To date, the rule is being reviewed by the Office of Management and Budget. This rule will have an impact on the Wyodak Plant. Until the EPA issues the rule for publication, we cannot quantify what the potential impact may be on the Wyodak Plant. The terms of this new regulation may impact the next permit renewal, which will be in 2020.reduce methane emissions.

Short-term Emission Limits. The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for SO2~~, NO~~xSO2, NOx and opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.

We proactively manage this requirement through maintenance efforts and installing additional pollution control systems to control SO2 SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut down the power plant ~~down~~ if ~~a predicted~~we anticipate the emission limit ~~is to~~will be exceeded. ~~Similar efforts~~There have been ~~taken~~limited instances of the trip logic mechanism being used and ~~similar results achieved with our natural gas fired combustion turbine sites as well.~~we experienced zero exceedances during 2020.

Regional Haze (Impacts to the Wyodak Plant). The EPA Regional Haze rule was promulgated to improve visibility in our National Parks and Wilderness Areas. The State of Wyoming proposed controls in its Regional Haze State Implementation Plan (SIP) which allowed PacifiCorp to install low-NO_x burners in the Wyodak Plant, of which South Dakota Electric owns 20%. The EPA did not agree with the State of Wyoming’s determination, ~~and~~ overruled it in a Federal Implementation Plan (FIP)~~. The~~ and proposed a Selective Catalytic Reactor to be installed to control NOx emissions. This would cost South Dakota Electric approximately $27 million due to its 20% ownership of the Wyodak Plant. PacifiCorp and the State of Wyoming ~~and other interested parties are challenging~~challenged the EPA’s determination. ~~If the challenge is unsuccessful, additional capital investment would be necessary~~Prior to ~~bring the Wyodak Plant into compliance. South Dakota Electric’s 20% share of this capital investment for the facility would be approximately $27 million if PacifiCorp is required to install a Selective Catalytic Reactor for~~ NO_x ~~control. The case is currently held in abeyance at the 10th circuit court as the parties work on a settlement. Basin Electric, who is part of the legal action, settled with the EPA. In lieu of going~~proceeding to court, PacifiCorp ~~entered into mediation with~~and the EPA reached a verbal agreement on December 16, 2020, to limit operating hours and ~~conservation groups. PacifiCorp submitted a “Request for Reconsideration” on October 24, 2019~~determined that low-NOx burners would be considered appropriate to control NOx emissions. This proposed agreement was published in the ~~EPA~~Federal Register, but remains in the public comment period until March 1, 2021. The final agreement must be published in the Federal Register and ~~provided a copy to~~approved in Wyoming’s State Implementation Plan through the ~~court. The purpose of the submittal is to revisit the emission impacts and cost of additional investment.~~rule making process.

Mining. Operations at the WRDC mine must regularly address issues related to the proximity of the mine disturbance boundary to the City of Gillette and to residential ~~and industrial~~ properties. Homeowner complaints and challenges to the permits may occur as mining operations move closer to residential areas. Specific concerns could include damage to wells, fugitive dust emissions, vibration and an emissions cloud from blasting. The mine makes every effort to reduce these impacts by monitoring blasts, modifying blast techniques to reduce blast vibration, applying dust suppression controls on roads and reclaiming lands to reduce windblown dust.

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Former Manufactured Gas Plants (FMGP). Federal and state laws authorize the EPA and other agencies to issue orders compelling potentially responsible parties to clean up sites that are determined to present an actual or potential threat to human health or the environment. ~~We are currently in discussions with the EPA, state regulators, and/or other third-parties to determine the ultimate resolution to these sites.~~ As of December 31, ~~2019,~~2020, our Gas Utilities have two active FMGP sites, which are located in Council Bluffs, Iowa, and McCook, Nebraska. ~~For~~At the Council Bluffs site, the ~~delay in clean-up is due~~EPA issued an order for the responsible parties to ~~identifying~~proceed with an Engineering Evaluation and Cost Analysis (EECA) to clean up the site. Three viable Potential Responsible Parties ~~(PRPs or Successors~~(PRP) continue to deny their legal attachment to the ~~Operators) to pay for~~site. The Company will continue conducting the ~~clean-up. We are~~EECA and anticipates pursuing the landowner and not the Successors to the Operator, whom would be responsible for paying for the majority of clean-up. We have been working with the EPA to identify the PRPs. The EPA has sent out information requests to the PRPs seeking transaction documents to determine the Successors to the Operators of the site who created the contamination. ForPRP’s through legal action. There is currently no action being taken at the McCook, Nebraska ~~site, we have been contacted by a~~site. A third-party ~~who intends~~initially indicated they intend to manage and pay for the clean-up at this site. ~~The~~However, after further investigation, the third-party ~~is conducting site assessments and working with~~assessed they owned the ~~State~~property after the gas plant ceased operations. We expect to conduct an assessment to determine viable PRPs.

For additional information, see Note 3 of ~~Nebraska~~the Notes to Consolidated Financial Statements in this Annual Report on ~~a clean-up plan.~~Form 10-K.

Affordable Clean Energy Rule. The EPA was directed to repeal, revise and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy (ACE) rule. This rule ~~focuses~~focused on heat-rate improvements on coal-fired boiler ~~units. In July 2019, the rule was finalized~~units and ~~applies~~applied only to our coal-fired plants. ~~These~~The Company’s coal-fired plants ~~have~~subject to the rule had implemented or ~~plan~~planned to implement a majority of the efficiency requirements listed in the rule. On January 19, 2021, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule. The court remanded the regulation regarding carbon dioxide emissions from existing power plants back to the EPA for reconsideration. Currently, there is no rule governing power plant GHG emissions and it is uncertain when a new rule will be promulgated.

OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR which is currently effective and establishes requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because ash is used for backfill reclamation in areas previously mined. The ~~current~~Office of Surface Mining (OSM) was considering CCR rules that would apply to the mine, but these rules were not proposed during the Trump administration. We will continue to monitor to see if the Biden administration ~~has not pursued further modification of the CCR.~~pursues these rules.

Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 193 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K.

Other Properties

In addition to the ~~facilities~~properties previously disclosed in ~~Items 1 and 2,~~the sections above, we own or lease several facilities throughout our service ~~territories. Our owned facilities are as follows:~~

~~In Rapid City, South Dakota, we have~~territories including a ~~220,000 square foot~~ corporate headquarters building ~~Horizon Point, which was completed in 2017.~~

~~In Arkansas, Colorado, Iowa, Kansas, Nebraska,~~ and ~~Wyoming we own~~ various office, service center, storage, shop and warehouse ~~space totaling over 1,030,000 square feet utilized by our Gas Utilities.~~

In Colorado, South Dakota, and Wyoming we own various office, service center, storage, shop and warehouse space totaling approximately 305,000 square feet utilized by our Electric Utilities and Mining segments.

~~In addition to our owned properties, we lease 92,527 square feet of properties within our service areas.~~

space. Substantially all of the tangible utility properties of South Dakota Electric and Wyoming Electric are subject to liens securing first mortgage bonds issued by South Dakota Electric and Wyoming Electric, respectively.

Human Capital Resources

Overview

Black Hills Corporation is committed to supporting operational excellence by attracting, motivating, retaining and encouraging the development of highly qualified employees. Our employees’ drive and dedication to their work, and their commitment to the safety of our customers and their fellow employees, allows Black Hills Corporation to successfully grow and manage our business year over year. The impacts of COVID-19 to our businesses and employees are discussed in the Company Highlights within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

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Our Team			As of December 31, 2020
Total employees			3,011
Gender diversity (women as a % of total employees)			26%
Women in executive leadership positions (a)			31%
Ethnic diversity (non-white employees as a % of total)			11%
Military veterans			16%
Represented by a union			25%

			For the year ended December 31, 2020
Number of external hires			299
External hires gender diversity (as a % of total external hires)			29%
External hires ethnic diversity (as a % of total external hires)			16%
Turnover rate (b)			8%
Retirement rate			3%

__________

(a) Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.

(b) Includes voluntary and involuntary separations, but excludes internships.

Total Employees


			Number of Employees
			At December 31, 2020
Electric Utilities			379
Gas Utilities			1,237

Power Generation and Mining			60
Corporate and Other			1,335
Total			3,011

At December 31, ~~2019, we had 2,944 employees. Approximately 25% of our employees are represented by a union. We have not experienced any labor stoppages in recent years. At~~ ~~December 31, 2019~~,2020, approximately ~~22%~~21% of our total employees and ~~25%~~23% of our Electric and Gas Utilities employees were eligible for regular (age 65 with at least 5 years of service) or early (ages 55 to 64 with at least 5 years of service) retirement.

~~The following table sets forth the number of employees included in continuing operations:~~



	~~Number of Employees~~
	~~At December 31, 2019~~
~~Corporate and Shared Services~~	~~1,273~~
~~Electric Utilities and Gas Utilities~~	~~1,609~~
~~Power Generation and Mining~~	62
~~Total~~	~~2,944~~

Collective Bargaining Agreements

At December 31, ~~2019~~,2020, certain employees of our Electric Utilities and Gas Utilities were covered by the ~~following~~ collective bargaining ~~agreements:~~

agreements as shown in the table below. We have not experienced any labor stoppages in decades.



Utility	Number of Employees	Union Affiliation	Expiration Date of Collective Bargaining Agreement
Colorado Electric	~~102~~95	IBEW Local 667	April 15, 2023
South Dakota Electric	~~135~~137	IBEW Local 1250	March 31, ~~2024~~2022
Wyoming Electric	2326	IBEW Local 111	June 30, 2024
Total Electric Utilities	258

Iowa Gas	~~113~~121	IBEW Local 204	~~July~~January 31, ~~2020~~2026
Kansas Gas	1817	Communications Workers of America, AFL-CIO Local 6407	December 31, 2024
Nebraska Gas	99100	IBEW Local 244	March 13, 2022
Nebraska Gas^(a)	~~146~~147	CWA Local 7476	October 30, ~~2019~~2023
Wyoming Gas^(a)	~~101~~15	IBEW Local 111	June 30, 2024
Wyoming Gas	84	CWA Local 7476	October 30, ~~2019~~2023
Total Gas Utilities	~~737~~484

~~__________~~


~~(a)~~			In the 2016 negotiations with the CWA Local 7476, the union agreed to disclaim their interest in Colorado Gas employees and to split the remaining bargaining unit into two distinct bargaining units, Nebraska Gas and Wyoming Gas. There are ongoing negotiations with both bargaining units at this time.


~~ITEM 1A.~~Total			~~RISK FACTORS~~742

~~OPERATING RISKS~~

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Attraction

Continuous attraction of qualified team members is critical to our ability to serve our 1.3 million customers safely and efficiently. We actively recruit diverse candidates and continuously evaluate our interviewing and hiring practices to ensure equitable pay and processes. Our attraction efforts include the use of multiple nation-wide job boards, local college and high school outreach programs, a strong college internship program and participation in national and local job fairs. Another key area of attraction is our commitment to our military personnel and veterans. We have targeted attraction efforts specific to military personnel transitioning into civilian life and for veterans of all types.

Diversity & Inclusion

At Black Hills Corporation, we believe in the benefits of diversity, equity and inclusion. We believe that a diverse workforce will assist us in achieving our goals of becoming the safest utility in the nation, providing exceptional customer service and achieving new levels of growth in a rapidly evolving industry. Workforce diversity trends, including diverse new hires, promotions and turnover, are monitored at regular intervals.

Development and Retention

Retaining and developing team members is critical to our continued success. Our retention efforts include competitive compensation programs, career development resources for all employees and internal training programs. Our compensation programs are designed to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective and legally compliant. Our career development resources include management onboarding, leadership development programs, mentoring programs, individual development assessments and more. Internal training opportunities include corporate-wide trainings such as our code of conduct and specialized training opportunities for different job functions. Our Field Career Path Program (FCPP) promotes career growth through established standards of knowledge, skills, abilities and performance.

ITEM 1A.RISK FACTORS

The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business operations, financial condition, results of operations or cash flows are described below. These risk factors, ~~and~~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 ~~and~~including our growth strategy.

Our ~~results of operations depend,~~success depends, in significant part, on our ability to execute our strategic business plans, ~~and~~including our growth strategy. ~~Technology advancements,~~Our plans and strategy include reducing GHG emissions for our Electric Utilities and Gas Utilities, transforming the customer experience, growing our electric and natural gas customer load, pursuing operating efficiencies and modernizing our utility infrastructure. Our current plans and strategy may be negatively impacted by disruptive forces and innovations in the marketplace, ~~and~~ changing political, business or regulatory conditions, ~~may negatively impact~~and technology advancements.

In addition, we have significant capital investment programs planned for the next five years that are key to our ~~current plans~~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 ~~strategies.~~ other prices, availability of materials, governmental approvals and permitting, regulatory cost recovery and return on investment.

An inability to successfully and timely adapt to changing conditions and execute our strategic plans, ~~and~~including our growth strategy could materially affect our financial operating results including earnings, cash flow and liquidity.

~~We may be subject to unfavorable federal and state regulatory outcomes.~~

Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and eight state utility commissions. This regulatory treatment does not provide any assurance as to achievementTable of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our various regulatory authorities will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in full recovery of our costs and the allowed return on invested capital. In addition, rate decisions could be influenced by many factors, including general economic conditions and the political environment.Contents

Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and the state utility commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. Any such costs not recovered through rates, or any such refund, could adversely affect financial operating results including earnings, cash flow and liquidity.

~~We may be subject to future laws, regulations, or actions associated with fossil-fuel generation and GHG emissions.~~

We own and operate regulated and unregulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase and deliver natural gas to our customers. These business activities are subject to evolving public concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.

Increased rules and regulations associated with fossil fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution, generation and storage facilities or coal mine. Further, these rules could create the need to purchase or build clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity.

~~Our financial performance depends on the successful management of our facilities operations, including ongoing operation, construction, expansion, and refurbishment.~~

Operation, construction, expansion and refurbishment of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities, and a coal mine involve risks that could result in fires, explosions, property damage and personal injury, including death. These risks include:

Inherent dangers. Electricity and natural gas are dangerous for employees and the general public; contact with power lines, natural gas pipelines, electrical or natural gas service facilities and equipment can result in fires and explosions, causing significant property damage and personal injuries, including death;

Weather, natural conditions and disasters. Severe weather events could negatively impact operations, including our ability to provide energy safely and reliably and our ability to complete construction, expansion or refurbishment of facilities as planned. Extreme natural conditions and other disasters such as wind, lightning, flooding and winter storms, can cause wildfires, electric transmission or distribution pole failures, natural gas pipeline interruptions, outages, property damage and personal injury;

~~Operating hazards. Operating hazards such as leaks, mechanical problems and accidents, including fires or explosions could impact employee and public safety, reliability and customer confidence;~~

Labor and labor relations. The cost of recruiting and retaining skilled technical labor or the unavailability of such resources could have a negative impact on our operations. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2019, approximately 25% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk; approximately 25% of our employees are represented by a total of eight collective bargaining agreements.

Equipment and processes. Breakdown or failure of equipment or processes, the unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations. New plants may employ recently developed and technologically complex equipment, including newer environmental emission control technology.

Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically, or with cyber means, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;

Natural gas supply for generation and distribution. Our utilities purchase natural gas from a number of suppliers for our generating facilities and for distribution to our customers. Our results of operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations, which could limit our utilities’ ability to operate their facilities;

~~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 environmental and pipeline safety laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;

~~Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses.~~

Disruption in the functioning of our information technology and network infrastructure which is vulnerable to disability, failures and unauthorized access. If our information technology systems were to fail and we were unable to recover in a timely manner, we would be unable to fulfill critical business functions.

The ongoing operation of our business involves the risks described above, in addition to risks associated with threats to our overall business model, such as electrification initiatives. Any of these risks could cause us to experience negative financial results and damage to our reputation and public confidence. These risks could cause us to incur significant costs or be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce revenues or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance and obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability or liquidated damage payments.

~~Our energy production, transmission and distribution activities, and our storage facilities for our natural gas involve numerous risks that may result in accidents and other catastrophic events.~~

Inherent in our businesses are a variety of hazards and operating risks, such as leaks, blowouts, fires, releases of hazardous materials, explosions and operational problems. Many of our transmission and distribution assets are located near populated residential areas, commercial business centers and industrial sites.

These hazards could result in injury or loss of human life, cause environmental pollution, significantly damage property or natural resources or impair our ability to operate our facilities. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully covered by our insurance and could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.

Customer growth and usage in our service territories may fluctuate with ~~current~~ economic conditions, emerging technologies or responses to price increases.

Our financial operating results are impacted by energy demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction ofin consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, economic conditions impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our financial operating results including earnings, cash flow and liquidity.

~~Cyberattacks, terrorism,~~REGULATORY, LEGISLATIVE AND LEGAL RISKS

We may be subject to future laws, regulations, or actions associated with climate change, including those relating to fossil-fuel generation and GHG emissions, which could increase our operating costs or restrict our market opportunities.

We own and operate regulated and unregulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase, store and deliver natural gas to our customers. These business activities are subject to evolving public concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.

~~To effectively operate our business, we rely upon a sophisticated electronic control system, SCADA, information technology systems~~regulations associated with fossil fuels and network infrastructure to collect and retain sensitive information including personal information about our customers and employees. Cyberattacks, terrorism or other malicious acts targeting electronic control systemsGHG emissions could result in ~~a full~~the impairment or ~~partial disruption~~retirement of some of our ~~electric and/~~existing or future transmission, distribution, generation and natural gas ~~operations. Attacks targeting other key information technology systems, including~~storage facilities or our ~~third-party vendors’ information systems,~~coal mine. Further, these rules could ~~further add~~create the need to ~~a full~~purchase or ~~partial disruption of~~build clean-energy fuel sources to fulfill obligations to our ~~operations. Any disruption of these operations~~customers. These actions could also result in ~~a loss of service to~~increased operating costs which could adversely impact customers and a significant decrease in revenues, as well as significant expense to repair system damage and remedy security breaches. Any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. The security measures and safeguards we have implemented may not always be effective. Despite our implementation of security measures and safeguards, all of our information technology systems may be vulnerable to disability, failures or unauthorized access

~~Risks associated with deployment of capital may impact our ability to execute our business plans and growth strategy.~~

We have significant capital investment programs planned for the next five years. The successful execution of our capital investment strategy depends on, or could be affected by, a variety of factors that include, but are not limited to: extreme weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, governmental approvals and permitting and regulatory cost recovery.

~~Weather conditions may cause fluctuation in customer usage as well as service disruptions.~~

Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation. Unusually mild summers and winters, therefore, could have an adverse effect on our results of operations, financial position or cash flows.

Our businesses are located in areas that could be subject to severe weather events such as snow and ice storms, tornadoes, strong winds, significant thunderstorms, flooding and drought. These events could result in lost operating revenues due to outages, property damage, including inoperable generation facilities and downed transmission and distribution lines, and storm restoration activities. We may not be able to recover the costs incurred following these weather events resulting in a negative impact on our financial operating results including earnings, cash flow and liquidity. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial condition or cash flows.

Future GHG constraints designed to minimize emissions from natural gas could likewise result in increased costs and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas. Certain cities in our operational footprint are focused on electrification and have adopted initiatives to prohibit the construction of new natural gas distribution facilities. Any such initiatives and legislation could have a material impact on our results of operations, financial condition and cash flows.

We may be subject to unfavorable or untimely federal and state regulatory outcomes.

Our regulated Electric and Gas Utilities are subject to cost-of-service/rate-of-return regulation and earnings oversight from federal and eight state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our customer rates are regulated by either the FERC or the respective state utility regulatory authority based on an analysis of our costs and investments, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our various regulatory authorities will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in full or timely recovery of our costs and the allowed return on invested capital. In addition, adverse rate decisions, including rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investments or rate reductions, could be influenced by competitive, economic, political, legislative, public perception and regulatory pressures and adversely impact results of operations, financial condition and cash flows.

Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased ~~risks~~fuel and purchased power costs or integrity capital investments) outside of a base rate review in order to stabilize customer rates and reduce regulatory lag. If regulators decide to discontinue these tariff-based recovery mechanisms, it could negatively impact results of operations, financial condition and cash flows.

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Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements.

Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions (i.e. SO2, NOx, volatile organic compounds, particulate matter and GHG), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure or inability to comply with evolving environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.

Our business segments may not be successful in recovering increased capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on our business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.

Legislative and regulatory requirements may lead to increased costs and result in compliance penalties.

Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many agencies employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, CFTC, EPA, OSHA, SEC and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business, which could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.

Certain Federal laws provide special protection to certain designated animal species. These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted activities that result in harm to or harassment of certain protected animals, including damage to their habitats. If such species are located in an area in which we conduct operations, or if additional species in those areas become subject to protection, our operations and development projects, particularly transmission, generation, wind and pipeline projects, could be restricted or delayed, or we could be required to implement expensive mitigation measures.

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.

~~FINANCING~~Changes in Federal tax law may significantly impact our business.

We are subject to taxation by the various taxing authorities at the federal, state and local levels where we do business. Similar to the TCJA, sweeping legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes may include numerous provisions that affect businesses, including changes to U.S. corporate tax rates, business-related exclusions, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which the effect of a change in corporate tax rate will impact our utility customers and the time period over which the impact will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.

OPERATING RISKS

Our financial performance depends on the successful operation of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities, and a coal mine.

The risks associated with management of these operations include:

•Inherent dangers. Electricity and natural gas can be dangerous to employees and the general public. Failures of or contact with power lines, natural gas pipelines or service facilities and equipment may result in fires, explosions, property damage and personal injuries, including death. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully covered by our insurance;

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•Weather, natural conditions and disasters. Severe weather events, such as snow and ice storms, fires, tornadoes, strong winds, significant thunderstorms, flooding and drought, could negatively impact operations, including our ability to provide energy safely, reliably and profitably and our ability to complete construction, expansion or refurbishment of facilities as planned;

•Acts of sabotage, terrorism or other malicious attacks. Damage to our facilities due to deliberate acts could lead to outages or other adverse effects;

•Operating hazards. Operating hazards such as leaks, mechanical problems and accidents, including fires or explosions could impact employee and public safety, reliability and customer confidence;

•Equipment and processes. Breakdown or failure of equipment or processes, unavailability or increased cost of equipment, and performance below expected levels of output or efficiency could negatively impact our results of operations;

•Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically, or with cyber means, our ability to sell or deliver utility services and satisfy our contractual obligations may be hindered;

•Natural gas supply for generation and distribution. Our regulated utilities and non-regulated entities purchase natural gas from a number of suppliers for our generating facilities and for distribution to our customers. Our results of operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather and environmental regulations;

•Replacement power. The cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities could negatively impact our results of operations;

•Governmental permits. The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate

and our results of operations;

•Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and contractual agreements, including those that restrict the timing of generation plant scheduled outages, could negatively impact our results of operations;

•Increased costs. Increased capital and operating costs to comply with increasingly stringent laws and regulations; unexpected engineering, environmental and geological problems; and unanticipated cost overruns could negatively impact our results of operations;

•Labor and labor relations. The cost of recruiting and retaining skilled technical labor or the unavailability of such resources could have a negative impact on our operations. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2020, approximately 23% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk; approximately 25% of our employees are represented by unions;

•Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses; and

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Cyberattacks, terrorism, or other malicious acts targeting our key technology systems could disrupt our operations, or lead to a loss or misuse of confidential and proprietary information.

To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive information including personal information about our customers and employees. Cyberattacks, terrorism or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or gas operations. Attacks targeting other key technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. Any disruption of these operations could result in a loss of service to customers and associated revenues, as well as significant expense to repair damages and remedy security breaches. In addition, any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data could subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators, among others.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. Despite our implementation of security measures and safeguards, all of our technology systems may still be vulnerable to disability, failures or unauthorized access.

Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our utility operations have historically generated lower revenues and income when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation. Unusually mild summers and winters, therefore, could have an adverse effect on our financial operating results, including earnings, cash flow and liquidity.

FINANCIAL RISKS

A sub-investment grade credit rating could impact our ability to access capital markets.

Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our investment grade credit ratings could impair our ability to refinance or repay our existing debt and complete new financings on reasonable terms, if at all. A credit rating downgrade, particularly to sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities, potentially significantly increasing our cost of capital and other associated operating ~~costs.~~costs which may not be recoverable through existing regulatory rate structures and contracts with customers.

~~Derivatives regulations could impede our ability to manage business and financial risks by restricting our~~Our use of derivative financial instruments as hedges against ~~fluctuating~~ commodity prices ~~and interest rates.~~

Dodd-Frank contains significant derivatives regulations, including a requirement that certain transactions be cleared resulting in a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users such as utilities and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.

We use derivative instruments for our hedging activities for our Gas and Electric Utilities’ operations. We may also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral for certain swap transactions we enter into. In addition, our exchange-traded futures contracts are subject to futures margin posting requirements, which could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.

~~Our hedging activities that are designed to protect against commodity price~~ and financial market risks ~~may cause fluctuations~~could result in ~~reported~~material financial ~~results due to mark-to-market accounting treatment.~~losses.

We use various financial ~~contracts~~ and physical derivatives, including futures, forwards, options and swaps to manage commodity price and ~~financial market~~interest rate risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities being hedged. ~~Fluctuating~~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 ~~could have a negative effect on our liquidity,~~may cause fluctuations in reported financial ~~condition, and~~ results ~~of operations.~~due to mark-to-market accounting treatment.

~~Our use of derivative financial instruments could result in material financial losses.~~

From time to time, we have sought to limit a portion of the potential adverse effects resulting from changes in commodity prices and interest rates by using derivative financial instruments and other hedging mechanisms. To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.

~~Market performance or changes in key valuation assumptions~~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 ~~require us to make significant unplanned contributions to our pension plans 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~~business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and ~~the expense recognized related~~ to ~~these plans. An adverse change~~protect cash flows. Requirements to ~~key assumptions associated with~~post collateral may cause significant liquidity issues by reducing our ~~defined benefit retirement plans~~ability to use cash for investment or other corporate purposes, or may require ~~significant unplanned contributions~~us to ~~the plans which~~increase our level of debt. Further, a requirement for our counterparties to post collateral could ~~adversely affect~~result in additional costs being passed on to us, thereby decreasing our ~~financial operating results including earnings, cash flow and liquidity.~~profitability.

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We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments are dependent upon cash distributions to the holding company from the subsidiaries.

As a holding company, our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital, equity or debt service funds.

There is no assurance as to the amount, if any, of future dividends to the holding company because ~~they~~these subsidiaries depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 9 of our Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.

We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, pay dividends and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings and proceeds from asset sales. Our ability to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.

In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in the context of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

A future recession or pandemic, if one occurs, may lead to an increase in late payments or non-payment from retail residential, commercial and industrial utility customers, as well as from our non-utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

~~Our ability~~We may be unable to obtain insurance coverage, and the ~~terms of any available insurance~~ coverage ~~could be adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. Our insurance coverage~~we currently have may not ~~provide protection against all~~apply or may be insufficient to cover a significant ~~losses.~~loss.

Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance ~~businesses, international, national, state or local events, as well as~~industry and the financial condition of insurers. ~~Insurance~~Additionally insurance providers could deny coverage ~~may not continue~~or decline to ~~be available at all,~~extend coverage under the same or ~~at rates or on~~similar terms ~~similar to those~~that are presently available to us. A loss for which we are not ~~fully~~adequately insured could materially ~~and adversely~~ affect our financial results. ~~Our insurance~~The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient ~~or effective under~~to cover all ~~circumstances and against all hazards or~~ liabilities to which the Company may be subject, including ~~but not limited to~~liability and losses associated with wildfire, natural gas and gas storage field explosions, cyber-security breaches, environmental hazards ~~fire-related liability from~~and natural ~~events~~disasters.

Market performance or ~~inadequate facility maintenance, distribution property losses, cyber-security risks~~changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and ~~dangers that exist in~~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 ~~gathering~~expense recognized related to these plans. An adverse change to key assumptions associated with our defined benefit retirement plans may require significant unplanned contributions to the plans which could adversely affect our financial operating results including earnings, cash flow and ~~transportation~~liquidity.

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Costs associated with our healthcare plans and other benefits could increase significantly.

The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have required, and likely will continue to require, changes to our current employee benefit plans and ~~in our~~supporting administrative ~~and accounting~~ processes. Our electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there ~~can be~~is no assurance that the state ~~public~~ utility commissions will allow ~~recovery.~~recovery of these increased costs. The ~~increasing cost,~~rising employee benefit costs, or inadequate recovery of ~~rising employee benefit~~such costs, may adversely affect our financial operating results including earnings, cash flow, or liquidity.

~~An effective system~~PANDEMIC RISK

Our business operations, results of ~~internal control may not~~operations, financial condition and cash flows could be ~~maintained, leading~~adversely affected by the coronavirus (COVID-19) pandemic.

We have responded to ~~material weaknesses~~the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.

For the year ended December 31, 2020, the COVID-19 pandemic had a limited net financial impact on our business operations, financial condition and cash flows. In particular, we experienced:

•Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;

•Increased costs due to sequestration of mission-critical and essential employees;

•Lower commercial and certain transport volumes partially offset by higher electric and natural gas residential usage;

•Waived customer late payment fees;

•Reduced availability of our employees;

•Increased costs for personal protection equipment and cleaning supplies;

•Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;

•Minimal impacts to the availability of our contractors;

•Minimal decline in ~~internal control over~~the funded status of our pension plan;

•Minimal interest expense increase due to disruptions in the Commercial Paper markets; and

•Reduced training, travel, and outside services related expenses.

Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business operations, financial ~~reporting.~~condition and cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:

~~Section 404~~•Adverse impacts on our strategic business plans, growth strategy and capital investments;

•Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;

•Further reduction in the availability of our employees and contractors;

•Increased costs as a result of our preventative measures, such as sequestration of essential employees and facility cleaning services;

•Increased allowance for credit losses and bad debt expense as a result of delayed or non-payment from our customers, both of which could be magnified by Federal or state government legislation that requires us to extend suspensions of disconnections for non-payment;

•Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;

•Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;

•Deterioration of the ~~Sarbanes-Oxley Act~~credit quality of 2002 requires management to make an assessment of the design and effectiveness of internal controls. Our independent registered public accounting firm is required to attest to the effectiveness of these controls. During their assessment of these controls, managementour counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or ~~our independent registered public accounting firm may identify areas of weakness in control design or effectiveness, which may lead to the conclusion~~retail customers, that a material weakness in internal control exists. Any control deficiencies we identify in the future could adversely affect our ability to report our financial results on a timely and accurate basis, which could result in ~~a loss~~credit losses;

•Impairment of ~~investor confidence in our financial reports~~goodwill or ~~have a material adverse effect~~long-lived assets;

•Adverse impacts on our ability to construct and operate ~~our business or access sources~~facilities;

•Inability to meet the requirements of ~~liquidity.~~

~~A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that~~ the control system’s objectives will be met. If we are unable to assert that our internal controls over financial reporting are effective, market perception of our business, operating results and stock price could be adversely affected.

~~ENVIRONMENTAL RISKS~~

Developments in federal and state laws concerning GHG regulations and air emissions relating to climate could materially increase our generation costs and render some of our generating units uneconomical to operate and maintain.

~~To the extent climate change occurs, our businesses could be adversely impacted. Warmer temperatures during the heating season~~covenants in our ~~utility service territories, or cooler temperatures during the cooling season~~existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;

•Deterioration in our ~~electric service territories could~~financial metrics or the business environment that adversely ~~affect financial results through lower natural gas volumes delivered, lower MWh sold~~impacts our credit ratings;

•Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and ~~associated lower revenues.~~

start dates of construction;

We own and operate regulated and non-regulated fossil-fuel generating plants in Colorado, South Dakota and Wyoming. Developments under federal and state laws and regulations governing air emissions from fossil-fuel generating plants may result in more stringent emission limitations, which could have a material•Adverse impact on our ~~costs~~liquidity position and cost of ~~operations. Various pending~~and ability to access funds from financial institutions and capital markets; and

•Delays in our ability to change rates through regulatory proceedings.

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To date, we have experienced limited impacts to our results of operations, financial condition, cash flows or ~~final state~~business plans. However, the situation remains fluid and ~~EPA regulations that will~~it is difficult to predict with certainty the potential impact ~~our facilities are also discussed in Item 1~~ of ~~this Annual Report on Form 10-K under the section “Environmental Matters~~”.

There is uncertainty surrounding current climate regulation due to legal challenges, new federal climate legislation anticipated in the future, or state climate legislation and regulation. We cannot definitively estimate the effect of GHG legislation or regulationCOVID-19 on our results of operations, financial ~~position or~~condition and cash flows.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or reduction of load of coal-fired power generation facilities and potential increased load of our combined cycle natural gas-fired generation units. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain; this could cause those generating units to be de-commissioned, potentially resulting in impairment costs. We will attempt to recover any remaining asset value; however, any unrecovered costs could have a material impact on our results of operations and financial condition.

~~The costs to achieve or maintain compliance with existing or future governmental laws, regulations or requirements, or failure to comply, could increase significantly.~~

Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.

The business segments may not be successful in recovering capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on the business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.

~~The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization.~~

~~Future regulations may require further reductions in emissions of mercury, hazardous pollutants, SO~~₂~~, NO~~_x, volatile organic compounds, particulate matter and GHG, which are released into the air when coal is burned. These requirements could require the installation of costly emission control technology or the implementation of other measures.

Coal competes with other energy sources, such as natural gas, wind, solar and hydropower. The EPA was directed to repeal, revise and replace the CPP rule. At this time, it is not known what effect this will have on coal as a domestic energy source, and could have a significant impact on our mining operations.ITEM 1B.UNRESOLVED STAFF COMMENTS

Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our financial operating results including earnings, cash flow and liquidity could be adversely impacted.


~~ITEM 1B.~~	~~UNRESOLVED STAFF COMMENTS~~

None.


~~ITEM 3.~~	~~LEGAL PROCEEDINGS~~

ITEM 3.LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 193, “~~Commitments~~“Commitments, Contingencies and ~~Contingencies~~”Guarantees”, of our Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K.

ITEM 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of 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

~~David R. Emery,~~ age 57, has been Executive Chairman since January 1, 2019, Chairman and Chief Executive Officer from 2016 through 2018, and Chairman, President and Chief Executive Officer from 2005 through 2015. Prior to that, he held various positions with the Company, including President and Chief Executive Officer and member of the Board of Directors from 2004 to 2005, President and Chief Operating Officer — Retail Business Segment from 2003 to 2004 and Vice President — Fuel Resources from 1997 to 2003. Mr. Emery has 30 years of experience with the Company.

Linden R. Evans, age ~~57,~~58, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer — Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 1819 years of experience with the Company.

Scott A. Buchholz, age ~~58,~~59, has been our Senior Vice President of Strategic Initiatives since July 2020. He served as Senior Vice President — Chief Information Officer ~~since~~from the closing of the Aquila Transaction in ~~2008.~~2008 to 2020. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 3940 years of experience with the Company, including 28 years with Aquila. Mr. Buchholz plans to retire on March 8, 2021.

Brian G. Iverson, age ~~57,~~58, has been Senior Vice President, General Counsel and Chief Compliance Officer since August 26, 2019. He served as Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary from February 1, 2019 to August 26, 2019, Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 1617 years of experience with the Company.

Richard W. Kinzley, age ~~54,~~55, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 2021 years of experience with the Company.

Jennifer C. Landis, age ~~45,~~46, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 1819 years of experience with the Company.

~~Karen Beachy,~~ age 48, has been Senior Vice President - Growth and Strategy since August 26, 2019. She served as Vice President - Growth and Strategy from 2018 to August 2019, Vice President - Supply Chain from 2016 to 2018, and Director of Supply Chain from 2014 to 2016. Ms. Beachy has 5 years of experience with the Company.

Stuart Wevik, age ~~58,~~59, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 3435 years of experience with the Company.

Erik Keller, age 57, joined the Company as Senior Vice President and Chief Information Officer on July 27, 2020. Prior to joining the company, he was an Information Technology consultant to Ontic Inc., a global provider of parts and services for legacy aerospace platforms, from January 2020 to July 2020, and Chief Information Officer for BBA Aviation, a global aviation support and aftermarket services provider, from February 2012 to January 2020.

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PART II


~~ITEM 5.~~	~~MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES~~

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of ~~December~~January 31, ~~2019~~,2021, we had ~~3,586~~3,537 common shareholders of record and ~~32,285~~46,737 beneficial owners, representing all 50 states, the District of Columbia and 6 foreign countries.

We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January ~~29, 2020~~27, 2021 meeting, our Board of Directors declared a quarterly dividend of ~~$0.535~~$0.565 per share, equivalent to an annual dividend rate of ~~$2.14~~$2.26 per share. This equivalent rate, if declared and paid in ~~2020,~~2021, will represent 5051 consecutive years of annual dividend increases.

For additional discussion of our dividend policy and factors that may limit our ability to pay dividends, see “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.

UNREGISTERED SECURITIES ISSUED

There were no unregistered securities sold during ~~2019.~~2020.

ISSUER PURCHASES OF EQUITY SECURITIES

The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2020:



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs









October 1, 2020 - October 31, 2020	1	$	53.95	—	—
November 1, 2020 - November 30, 2020	804	58.63		—	—
December 1, 2020 - December 31, 2020	7,569	59.66		—	—
Total	8,374	$	59.56	—	—

_____________

(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.



~~There were no equity securities acquired for the twelve months ended December 31, 2019.~~


~~ITEM 6.~~	~~SELECTED FINANCIAL DATA~~

~~(Minor differences may result due to rounding)~~

Years Ended December 31, 2019 2018 2017
2016 ^(a)
2015
(dollars in thousands, except per share amounts)

Total Assets
$ 7,558,457
$ 6,963,327
$ 6,658,902
$ 6,541,773
$ 4,626,643

Property, Plant and Equipment

Property, plant and equipment $ 6,784,679
$ 6,000,015
$ 5,567,518
$ 5,315,296
$ 3,849,309

Accumulated depreciation and depletion (1,281,493 ) (1,145,136 ) (1,026,088 ) (929,119 ) (794,695 )
Total property, plant and equipment, net $ 5,503,186
$ 4,854,879
$ 4,541,430
$ 4,386,177
$ 3,054,614

Capital Expenditures
Continuing Operations $ 849,755
$ 502,424
$ 337,689
$ 460,450
$ 289,896

Discontinued Operations ^(b)
—
2,402
23,222
6,669
168,925

Total Capital Expenditures $ 849,755
$ 504,826
$ 360,911
$ 467,119
$ 458,821

Capitalization (excluding noncontrolling interests)

Current maturities of long-term debt $ 5,743
$ 5,743
$ 5,743
$ 5,743
$ —

Notes payable 349,500
185,620
211,300
96,600
76,800

Long-term debt, net of current maturities 3,140,096
2,950,835
3,109,400
3,211,189
1,853,682

Total stockholders’ equity 2,362,123
2,181,588
1,708,974
1,614,639
1,465,867

Total capitalization $ 5,857,462
$ 5,323,786
$ 5,035,417
$ 4,928,171
$ 3,396,349

Total Operating Revenues $ 1,734,900
$ 1,754,268
$ 1,680,266
$ 1,538,916
$ 1,261,322

Net Income Available for Common Stock
Income from continuing operations available for common stock 199,310
(c) (g) 265,329
(c)(f) 194,133
(c) (d) 137,132
(c) (d) 141,548
(d)
Income (loss) from discontinued operations, net of tax ^(b)
—
(6,887 ) (17,099 ) (64,162 ) (173,659 )
Net income (loss) available for common stock $ 199,310
$ 258,442
$ 177,034
$ 72,970
$ (32,111 )

Common Stock Data^(e) (in thousands)

Shares outstanding, average basic 60,662
54,420
53,221
51,922
45,288

Shares outstanding, average diluted 60,798
55,486
55,120
53,271
45,288

Shares outstanding, end of year 61,477
60,004
53,541
53,382
51,192

ITEM 6.SELECTED FINANCIAL DATA ~~continued~~

We have early adopted the new SEC amendments to modernize, simplify, and enhance certain financial disclosure requirements in Regulation S-K which, among other things, eliminates the requirement to present Selected Financial Data.

Years Ended December 31, 2019 2018 2017 2016 2015
(dollars in thousands, except per share amounts)

Earnings (Loss) Per Share of Common Stock (in dollars)

Basic earnings (loss) per average share -
Continuing operations $ 3.52
$ 5.14
$ 3.92
$ 2.83
$ 3.12

Discontinued operations ^(b)
—
(0.13 ) (0.32 ) (1.23 ) (3.83 )
Non-controlling interest ^(c)
(0.23 ) (0.26 ) (0.27 ) (0.19 ) —

Total $ 3.29
$ 4.75
$ 3.33
$ 1.41
$ (0.71 )
Diluted earnings (loss) per average share -
Continuing operations $ 3.51
$ 5.04
$ 3.78
$ 2.75
$ 3.12

Discontinued operations ^(b)
—
(0.12 ) (0.31 ) (1.20 ) (3.83 )
Non-controlling interest ^(c)
(0.23 ) (0.26 ) (0.26 ) (0.18 ) —

Total $ 3.28
$ 4.66
$ 3.21
$ 1.37
$ (0.71 )

Cash Dividends Paid on Common Stock $ 124,647
$ 106,591
$ 96,744
$ 87,570
$ 72,604

Dividends Declared per Share $ 2.05
$ 1.93
$ 1.81
$ 1.68
$ 1.62

Book Value Per Share, End of Year $ 38.42
$ 36.36
$ 31.92
$ 30.25
$ 28.63

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~~(a)~~

Effective February 12, 2016, we completed the SourceGas Transaction. Total cash consideration paid, net of debt assumed and working capital adjustment received, was $1.124 billion, funded with a combination of the issuance of 6.3 million shares of our common stock on November 23, 2015, 5.98 million equity units issued on November 23, 2015, $546 million of net proceeds from the issuance of senior unsecured notes on January 13, 2016, cash on hand and draws under our revolving credit facility.

~~(b)~~

On November 1, 2017, we made the decision to divest our Oil and Gas assets which was completed in 2018. Oil and Gas results are shown in discontinued operations. 2017 includes a non-cash after-tax fair value impairment on held-for-sale assets of $13 million. 2016 includes non-cash after-tax impairment charges to crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax impairment charges to crude oil and natural gas properties of $158 million.


~~(c)~~	On April 14, 2016, Black Hills Electric Generation sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2019, 2018, 2017 and 2016 was reduced by $14 million, $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest.


~~(d)~~	~~2017, 2016 and 2015 include incremental SourceGas Transaction costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively.~~


~~(e)~~	In 2019, we issued 1.33 million shares at an average share price of $75.28 under our ATM equity offering program. On November 1, 2018, we issued 6.3 million shares of common stock upon conversion of our Equity Units. In 2016, we issued 1.97 million shares at an average share price of $60.95 under our ATM equity offering program.


~~(f)~~	~~The increase in 2018 included a $73 million tax benefit resulting from legal entity restructuring. See~~ ~~Note 15~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.~~


~~(g)~~	~~2019 includes a non-cash after-tax impairment of $15 million in our investment in equity securities of a privately held oil and gas company. See~~ ~~Note 1~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.~~

~~For additional information on our business segments see~~ ~~Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,~~ ~~Item 7A, Quantitative and Qualitative Disclosures about Market Risk and~~ ~~Note 5~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~

~~ITEMS 7 & and 7A.~~ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ~~AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

Executive Summary

We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of ~~improving life~~Improving Life with ~~energy~~Energy and a vision to be the ~~energy partner~~Energy Partner of ~~choice.~~Choice. The Company provides ~~electricity~~electric and natural gas ~~through its Electric and Gas Utilities~~utility service to 1.3 million customers ~~in 824~~over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. We conduct our business operations through four reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company’s Electric Utilities are supported by our Power Generation and Mining ~~segments.~~segments, which are mostly contracted to company affiliates and subject to utility-like regulation and oversight. The Power Generation segment produces electric power from its five generating facilities and sells most of the electric capacity and energy to our Electric Utilities under mid- and long-term contracts. ~~Our~~The Mining segment, ~~produces~~consisting of a single coal ~~at our only location~~mine near Gillette, Wyoming, ~~and~~ sells nearly all production to fuel the five on-site, mine-mouth power generation facilities. With more than 90% of the Company’s assets directly invested in its regulated utility businesses and the Power Generation and Mining segments supporting its electric utilities mainly through long-term contracts, the Company considers itself a domestic, pure-play electric and natural gas utility company.

The Company has provided energy and served customers for ~~136~~137 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. Our strategic focus has not changed in over a century - serving customers with affordable, reliable and safe ~~energy.~~energy and being strong environmental stewards. Our strategy today continues that emphasis on serving customers ~~but with a renewed focus on better engaging with~~and being responsive to the people and communities we serve. Customer expectations are rapidly changing with the advancement of technology and customers are demanding simpler, faster and more convenient solutions to their energy needs. WeCustomers and other stakeholders are demanding cleaner energy solutions to address concerns around carbon emissions. In this rapidly changing energy environment, we are Ready to ~~serve as we have done for the past 136 years.~~serve.

Our strategy ~~consists of five primary areas that focus~~focuses on improving the way we serve customers with safe, reliable, affordable and ~~affordable~~cleaner energy while improving the lives of the customers and communities we serve. ~~The strategy~~Our emphasis is ~~to 1) become the safest energy company~~on consistently outperforming utility industry averages in ~~the utility industry; 2) transform~~key safety metrics; transforming the customer experience; ~~3) grow~~growing our electric and natural gas customer load; ~~4) pursue~~pursuing operating efficiencies; and ~~5) modernize~~modernizing utility infrastructure. ~~This strategic~~These areas of focus will present the company with significant investment needs as we modernize our infrastructure systems, ~~and~~ meet customer ~~growth.~~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 interactions.

Key Elements of our Business Strategy

Modernize, replace and operate utility infrastructure to meet our customers’ energy needs while providing safe, reliable, affordable and ~~affordable~~cleaner energy. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that ~~span~~spans nearly 1,600 ~~miles.~~miles of the United States. Our Electric Utilities own and operate ~~939~~992 MW of generation capacity and 8,900 miles of transmission and distribution lines and our Gas Utilities own and operate ~~46,000~~47,000 miles of natural gas transmission and distribution pipelines. A key strategic focus is to modernize this utility infrastructure to meet customers’ and communities’ varied energy needs, ~~and to~~ ensure the continued delivery of safe, reliable and affordable ~~energy.~~energy and reduce GHG emission intensity. In addition, we ~~need to~~ invest in the accessibility, 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~~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, our Electric Utilities utilize a distribution integrity program to ensure the timely repair and replacement of aging infrastructure. Our Gas Utilities utilize a programmatic approach to system-wide pipeline ~~system~~ 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. ~~Many~~All but one of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments which reflect the cost incurred in repairing and replacing the gas delivery systems.

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As of December 31, 2020, we estimate our five-year capital investment to be approximately $2.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure and to support customer and community growth needs. Our actual ~~2019~~2020 and forecasted capital expenditures and depreciation for the next five years from ~~2020~~2021 through ~~2024~~2025 are as follows (in millions):


	Actual		Forecasted
Capital Expenditures By Segment (a) :	2020		2021		2022		2023		2024		2025
(in millions)
Electric Utilities	$	271	$	240	$	180	$	143	$	156	$	154
Gas Utilities	449		377		347		339		330		326
Power Generation	9		10		9		6		4		5
Mining	8		9		9		9		9		10
Corporate and Other	18		11		5		13		13		13
Total	$	755	$	647	$	550	$	510	$	512	$	508

Actual Planned Planned Planned Planned Planned
Capital Expenditures By Segment 2019 2020 2021 2022 2023 2024
(in millions)
Electric Utilities $ 223
$ 246
$ 203
$ 170
$ 137
$ 152
Gas Utilities 512
391
309
285
316
293
Power Generation 85
7
9
11
6
6
Mining 9
8
12
9
9
9
Corporate and Other 21
17
22
11
12
10
Total $ 850
$ 669
$ 555
$ 486
$ 480
$ 470
____________________________

(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.

Efficiently plan, construct and operate rate base power generation facilities to serve our Electric Utilities. We believe that we best serve customers and communities with a vertically integrated business model for our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to cost-effectively supply electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.

Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs, efficiency in converting fuel into energy, low per unit operating and maintenance costs and high levels of power plant availability. For our coal-fired power plants, we leverage our mine-mouth location advantage to eliminate coal transportation costs that often represent the largest component of the delivered cost of coal for many other utilities. Additionally, we operate our plants with high levels of availability as compared to industry benchmarks.

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We continue to believe that ownership of power generation facilities by our Electric Utilities best serves customers. Rate-based generation assets offer several advantages for customers and shareholders, including:

•When generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run; especially when compared to power otherwise purchased from the open market through wholesale contracts that are periodically re-priced to reflect current and varying market conditions;

•Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;

•The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of capital; and

•Investors are provided a long-term ~~reasonable,~~and stable return on their investment.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. ~~Some~~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 25% reduction from our Electric Utilities. Colorado Electric has achieved an approximate 50% reduction in GHG emissions since 2005 and is on track to reach 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 ~~more renewable and~~ cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from ~~voters,~~consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. To support this interest, we ~~have~~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 agency customer requests for renewable energy ~~resources in South Dakota and Wyoming.~~resources. To meet the renewable energy commitments under the new tariffs, on November 30, 2020, we ~~also received approval from the Wyoming Public Service Commission to build~~completed construction and placed into service the Corriedale wind project, a 52.5 MW wind ~~farm to be constructed~~energy project near Cheyenne, Wyoming. ~~The $79 million project is expected to be in service by year-end 2020.~~ Supporting our renewable energy efforts in Colorado, in ~~November 2019, we successfully commissioned Busch Ranch II, a 60~~September 2020, Colorado Electric received approval from the CPUC for its request for approval of its preferred solar bid in support of its Renewable Advantage program, which plans to add up to 200 MW ~~wind farm near Pueblo, Colorado, to provide~~of renewable energy ~~to our Colorado Electric utility.~~by the end of 2023.

To date, 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 ~~emissions~~emission reduction targets. Federal legislation for ~~both~~ renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely 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 affordable 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.

Build and maintain strong relationships with wholesale power customers of our utilities and our power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be an important provider of electricity to wholesale utility customers, who will continue to need products such as capacity and energy to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns for shareholders over the long-term than we would by selling energy into more volatile energy spot markets. In addition, relationships that we have established with wholesale power customers have developed into other opportunities. MEAN, MDU and the City of Gillette, Wyoming were wholesale power customers that are now joint minority owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues.

Vertically integrate businesses that are supportive of our Electric and Gas ~~utility~~Utility businesses. While our primary focus is onserving customers and growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to our utilities. We currently own and operate power generation and mining assets that are vertically integrated into and ~~supportive of~~support our Electric Utilities. These operations are located at our utility-generating complexes and are physically integrated into our Electric ~~Utility~~Utilities’ operations.

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The Power Generation segment currently owns five power facilities, four of which are contracted with our affiliate Electric Utilities under mid- to long-term power purchase agreements. Our Power Generation segment has an experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed ~~20 coal-fired, gas-fired and renewable~~22 generation projects since 1995 with an aggregate ~~project costs~~investment in excess of ~~$2.1~~$2.5 billion. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the company’s generation assets. In certain states, our Electric Utilities are required to competitively bid for generation resources needed to serve customers. Generally, our Power Generation segment submits bids in response to those competitive solicitations. Our Power Generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs.

Our small surface coal mine is located immediately adjacent to our Gillette energy complex in northeastern Wyoming, where all five of our remaining coal-fired power plants are located. We operate and own majority interests in four of ~~our~~the five power plants. We own 20% of the fifth power plant which is operated by a majority owner. The mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our power plants when compared to other coal-fired and natural gas-fired ~~power plants.~~generating facilities. Nearly all of the mine’s production is sold to the five on-site, mine-mouth 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.

~~Expand utility operations through selective acquisitions of electric and gas utilities.~~ The electric and natural gas utility industries have consolidated significantly over the past two decades and continue to consolidate. We have successfully acquired and integrated numerous utility systems since 2005, including two large, transformational acquisitions - the Aquila Transaction in 2008 and SourceGas Transaction in 2016. Through these acquisitions, we developed a scalable platform that simplifies the rapid integration of acquired utilities, providing significant benefits to both customers and shareholders. The company targets small to large utilities, including municipal and private utility systems, located primarily in geographies that are near to or contiguous with our existing utility service territories and can provide long-term value for both customers and shareholders. In the near-term, we do not expect to pursue large utility acquisitions, particularly given the high valuation multiples realized in recent utility transactions. As pipeline regulations continue to increase, we believe there will be more opportunities to purchase these smaller and more rural utility systems.

Grow our dividend. We are extremely proud of our track record of annual dividend increases for shareholders. 2020 represented our 50th consecutive year of increasing dividends. In January ~~2020,~~2021, our Board of Directors declared a quarterly dividend of ~~$0.535~~$0.565 per share, equivalent to an annual dividend of ~~$2.14~~$2.26 per share. ~~This current annual equivalent rate of $2.14 per share, if declared and paid in 2020, will represent 50 consecutive years of annual dividend increases.~~ We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and ~~earnings accretive~~earnings-accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating.

~~Prospective Information~~Power Generation

Our Power Generation segment, which operates through Black Hills Electric Generation and its subsidiaries, acquires, develops, constructs and operates our non-regulated power plants. As of December 31, 2020, we held varying interests in independent power plants with a total net ownership of 423 MW.

We ~~expect~~produce electric power from our generating facilities and sell the electric capacity and energy, primarily to ~~generate~~affiliates under a combination of mid- to long-term ~~growth~~contracts, which mitigates the impacts of volatility in future power prices and fluctuations in demand.

As of December 31, 2020, the power plant ownership interests held by our Power Generation segment include:


Power Plants	Fuel Type	Location	Ownership Interest % (d)	Owned Capacity (MW)	In Service Date
Wygen I	Coal	Gillette, Wyoming	76.5%	68.9	2003
Pueblo Airport Generation (a)	Gas	Pueblo, Colorado	50.1%	200.0	2012
Busch Ranch I (b)	Wind	Pueblo, Colorado	50.0%	14.5	2012
Busch Ranch II (c)	Wind	Pueblo, Colorado	100.0%	60.0	2019
Top of Iowa (c)	Wind	Joice, Iowa	100.0%	80.0	2019
				423.4

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(a) In 2016, Black Hills Electric Generation sold a 49.9% noncontrolling interest in Black Hills Colorado IPP to a third party. See Note 14 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

(b) In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act.

(c) The Busch Ranch II and Top of Iowa facilities qualify for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date each facility was originally placed in service.

(d) Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Power Sales Agreements and Operating Agreements. Our Power Generation facilities have various mid- to long-term power sales agreements and operating agreements. Key contracts are disclosed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess.

With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity and foster competition within the wholesale electricity markets. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for IPPs in some regions. To date, these initiatives have not had a material impact on our Power Generation segment.

The Energy Policy Act of 1992 and Public Utility Holding Company Act of 2005 (PUHCA 2005). PUHCA 2005 reiterated the definition and benefits of Exempt Wholesale Generator (EWG) status. Under PUHCA 2005, an EWG is an entity or generator engaged, directly or indirectly through the expansion of integrated utilities and supporting operations. Sustained growth requires continued capital deployment. Our integrated energy portfolio, focused predominately on regulated utilities, provides growth opportunities, yet avoids concentrating business risk. We expect much of our growthone or more affiliates, exclusively in the ~~next few years will come~~business of owning, operating or both owning and operating all or part of one or more eligible facilities and selling electric energy at wholesale. Though EWGs are public utilities within the definition set forth in the Federal Power Act and are subject to FERC regulation of rates and charges, they are exempt from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with three EWGs, Wygen I, Pueblo Airport Generating and Top of Iowa. Each of these three EWG’s have been granted market-based rate authority.

Operating statistics. See a summary of key operating statistics in the need for capital deployment at our utilities and continued focus on improving efficiencies and controlling costs. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet ourPower Generation segment operating capital and financing needs, as well as executing our long-term strategic plan. Prospective information for our operating segments should be read in conjunction with our business strategy discussed above, and our 2019 company highlights discussed below.

~~Our discussion and analysis for the year ended December 31, 2019 compared to 2018, as well as discussion and analysis of the~~ results of operations for the year ended December 31, 2018 compared to 2017 given segment reporting changes adopted by the Company in 2019, is included herein. For further discussion and analysis that remains unchanged for the year ended December 31, 2018 compared to 2017, please refer to Item 7 of Part II, “Management’swithin Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations”~~Operations in Item 7 of this Annual Report on Form 10-K.

Mining

Our Mining segment operates a single coal mine through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC mine, which we acquired in 1956 from Homestake Mining Company, is located in the Powder River Basin. We produced approximately 3.7 million tons of coal in 2020.

In a basin characterized by thick coal seams, our overburden ratio, a comparison of the cubic yards of dirt removed to a ton of coal uncovered, has trended upwards over the last fifteen years. However, the overburden ratio at December 31, 2020 was 2.17 which decreased from 2.30 in the prior year as we mined in areas with lower overburden. We expect our stripping ratio to increase to approximately 2.27 by the end of 2021 as we mine in areas with higher overburden.

We pay federal and state royalties of 12.5% of the selling price of all coal. As of December 31, 2020, we estimated our recoverable reserves to be approximately 182 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable reserve life is equal to approximately 49 years at the current production levels. Our recoverable reserve estimates are periodically updated to reflect past production and other geological and mining data. Changes in mining methods or the utilization of new technologies may increase or decrease the recovery basis for a coal seam. Our recoverable reserves include reserves that can be economically and legally extracted at the time of their determination.

Substantially all of the mine’s production is currently sold under contracts to:

•South Dakota Electric for use at the 90 MW Neil Simpson II plant to which we sell approximately 500,000 tons each year. This contract is for the life of the plant;

•Wyoming Electric for use at the 95 MW Wygen II plant to which we sell approximately 550,000 tons each year. This contract is for the life of the plant;

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•The 110 MW Wygen III power plant jointly owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons each year;

•The 90 MW Wygen I power plant jointly owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons each year; and

•Certain regional industrial customers served by truck to which we sell a total of approximately 300,000 tons each year. These contracts have terms of one to five years.

In October 2019, negotiations were completed for the price re-opener in the contract with the Wyodak Plant. The new price was

WRDC supplies coal to Black Hills Wyoming for the Wygen I generating facility for requirements under an agreement through June 30, 2038. Currently, this agreement uses a base price that includes price escalators and quality adjustments and includes actual cost per ton plus a margin equal to the yield for Moody’s A-Rated Utility Bond Index plus 400 basis points with the base price being adjusted on a 5-year interval. Effective January 1, 2022, in conjunction with the new Wygen I 60 MW PPA, WRDC’s current coal supply agreement will be revised using pricing that will be cost-based to regulate earnings to a specified return on the cost-depreciated investment base. For additional information regarding the new Wygen I 60 MW PPA, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental and availability considerations affect the overall demand for coal as a fuel.

Mine Reclamation. Reclamation is completed during production and after mining has finished. Under applicable law, we must submit applications to, and receive approval from, the Wyoming Department of Environmental Quality for any mining and reclamation plans that provide for orderly mining, reclamation and restoration of the WRDC mine. We have approved mining permits and are in compliance with other permitting programs administered by various regulatory agencies. The WRDC mine is permitted to operate under a five-year mining permit issued by the State of Wyoming. In 2016, that five-year permit was re-issued and we are currently in the process of renewing this permit. Based on extensive reclamation studies, we have accrued approximately $13 million for reclamation costs as of December 31, 2020. See additional information in Note 7 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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Environmental Matters

Methane Rules (Greenhouse Gas Emissions). The EPA and the State of Colorado have implemented strict regulatory requirements on hydrocarbon and methane emissions associated with natural gas gathering and transmission systems. Presently, we have facilities in our natural gas transmission operations affected by the methane reduction rules.

Our operations are in compliance with both EPA and State of Colorado rules. Future modifications to our gathering and transmissions systems are anticipated to trigger EPA methane rules that we will adhere to. We developed a corporate-wide methane control strategy to address GHG emissions. As a proactive measure in reducing methane emissions beyond current regulatory requirements, we have entered into the EPA’s Methane Challenge Program. This is a voluntary program founded by the EPA in collaboration with oil and natural gas companies that recognizes companies that make specific and transparent commitments to reduce methane emissions.

Short-term Emission Limits. The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for SO2, NOx and opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.

We proactively manage this requirement through maintenance efforts and installing additional pollution control systems to control SO2 emission short-term excursions during start-up. These actions have nearly eliminated our short-term emission limit compliance risk while plant availability remained above 90% for all four of our coal-fired plants. To eliminate the remaining potential for exceedances, an innovative trip logic mechanism was implemented to shut down the power plant if we anticipate the emission limit will be exceeded. There have been limited instances of the trip logic mechanism being used and we experienced zero exceedances during 2020.

Mining. Operations at the WRDC mine must regularly address issues related to the proximity of the mine disturbance boundary to the City of Gillette and to residential properties. Homeowner complaints and challenges to the permits may occur as mining operations move closer to residential areas. Specific concerns could include damage to wells, fugitive dust emissions, vibration and an emissions cloud from blasting. The mine makes every effort to reduce these impacts by monitoring blasts, modifying blast techniques to reduce blast vibration, applying dust suppression controls on roads and reclaiming lands to reduce windblown dust.

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For additional information, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Affordable Clean Energy Rule. The EPA was directed to repeal, revise and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy (ACE) rule. This rule focused on heat-rate improvements on coal-fired boiler units and applied only to our coal-fired plants. The Company’s coal-fired plants subject to the rule had implemented or planned to implement a majority of the efficiency requirements listed in the rule. On January 19, 2021, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule. The court remanded the regulation regarding carbon dioxide emissions from existing power plants back to the EPA for reconsideration. Currently, there is no rule governing power plant GHG emissions and it is uncertain when a new rule will be promulgated.

OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR which is currently effective and establishes requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because ash is used for backfill reclamation in areas previously mined. The Office of Surface Mining (OSM) was considering CCR rules that would apply to the mine, but these rules were not proposed during the Trump administration. We will continue to monitor to see if the Biden administration pursues these rules.

Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Other Properties

In addition to the properties previously disclosed in the sections above, we own or lease several facilities throughout our service territories including a corporate headquarters building and various office, service center, storage, shop and warehouse space. Substantially all of the tangible utility properties of South Dakota Electric and Wyoming Electric are subject to liens securing first mortgage bonds issued by South Dakota Electric and Wyoming Electric, respectively.

Human Capital Resources

Overview

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Our Team			As of December 31, 2020
Total employees			3,011
Gender diversity (women as a % of total employees)			26%
Women in executive leadership positions (a)			31%
Ethnic diversity (non-white employees as a % of total)			11%
Military veterans			16%
Represented by a union			25%

			For the year ended December 31, 2020
Number of external hires			299
External hires gender diversity (as a % of total external hires)			29%
External hires ethnic diversity (as a % of total external hires)			16%
Turnover rate (b)			8%
Retirement rate			3%

__________

(a) Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.

(b) Includes voluntary and involuntary separations, but excludes internships.

Total Employees


			Number of Employees
			At December 31, 2020
Electric Utilities			379
Gas Utilities			1,237

Power Generation and Mining			60
Corporate and Other			1,335
Total			3,011

At December 31, 2020, approximately 21% of our total employees and 23% of our Electric and Gas Utilities employees were eligible for regular (age 65 with at least 5 years of service) or early (ages 55 to 64 with at least 5 years of service) retirement.

Collective Bargaining Agreements

At December 31, 2020, certain employees of our Electric Utilities and Gas Utilities were covered by the collective bargaining agreements as shown in the table below. We have not experienced any labor stoppages in decades.


Utility	Number of Employees	Union Affiliation	Expiration Date of Collective Bargaining Agreement
Colorado Electric	95	IBEW Local 667	April 15, 2023
South Dakota Electric	137	IBEW Local 1250	March 31, 2022
Wyoming Electric	26	IBEW Local 111	June 30, 2024
Total Electric Utilities	258

Iowa Gas	121	IBEW Local 204	January 31, 2026
Kansas Gas	17	Communications Workers of America, AFL-CIO Local 6407	December 31, 2024
Nebraska Gas	100	IBEW Local 244	March 13, 2022
Nebraska Gas	147	CWA Local 7476	October 30, 2023
Wyoming Gas	15	IBEW Local 111	June 30, 2024
Wyoming Gas	84	CWA Local 7476	October 30, 2023
Total Gas Utilities	484

Total	742

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Attraction

Diversity & Inclusion

Development and Retention

ITEM 1A.RISK FACTORS

The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business operations, financial condition, results of operations or cash flows are described below. These risk factors, along with other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.

STRATEGIC RISKS

Our continued success is dependent on execution of our strategic business plans including our growth strategy.

Our success depends, in significant part, on our ability to execute our strategic business plans, including our growth strategy. Our plans and strategy include reducing GHG emissions for our Electric Utilities and Gas Utilities, transforming the customer experience, growing our electric and natural gas customer load, pursuing operating efficiencies and modernizing our utility infrastructure. Our current plans and strategy may be negatively impacted by disruptive forces and innovations in the marketplace, changing political, business or regulatory conditions, and technology advancements.

In addition, we have significant capital investment programs planned for the next five years that are key to our strategic business plans. The successful execution of our capital investment program depends on, or could be affected by, a variety of factors that include, but are not limited to: weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, availability of materials, governmental approvals and permitting, regulatory cost recovery and return on investment.

An inability to successfully and timely adapt to changing conditions and execute our strategic plans, including our growth strategy could materially affect our financial operating results including earnings, cash flow and liquidity.

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Customer growth and usage in our service territories may fluctuate with economic conditions, emerging technologies or responses to price increases.

Our financial operating results are impacted by energy demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction in consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, economic conditions impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our financial operating results including earnings, cash flow and liquidity.

REGULATORY, LEGISLATIVE AND LEGAL RISKS

There is uncertainty surrounding climate regulation due to legal challenges to some current regulations and anticipated new federal and/or state climate legislation and regulation. The Biden administration has issued executive orders aimed at reducing GHG emissions and declared climate change a national security policy for the first time. New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or capacity reductions of coal-fired power generation facilities and potential increased production from our combined cycle natural gas-fired generating units. Increased rules and regulations associated with fossil fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution, generation and natural gas storage facilities or our coal mine. Further, these rules could create the need to purchase or build clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity. We cannot definitively estimate the effect of GHG legislation or regulation on our results of operations, financial condition or cash flows.

We may be subject to unfavorable or untimely federal and state regulatory outcomes.

Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs or integrity capital investments) outside of a base rate review in order to stabilize customer rates and reduce regulatory lag. If regulators decide to discontinue these tariff-based recovery mechanisms, it could negatively impact results of operations, financial condition and cash flows.

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Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements.

Legislative and regulatory requirements may lead to increased costs and result in compliance penalties.

Municipal governments may seek to limit or deny our franchise privileges.

Changes in Federal tax law may significantly impact our business.

OPERATING RISKS

The risks associated with management of these operations include:

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•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;

•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;

and our results of operations;

•Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses; and

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Cyberattacks, terrorism, or other malicious acts targeting our key technology systems could disrupt our operations, or lead to a loss or misuse of confidential and proprietary information.

Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

FINANCIAL RISKS

A sub-investment grade credit rating could impact our ability to access capital markets.

Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our investment grade credit ratings could impair our ability to refinance or repay our existing debt and complete new financings on reasonable terms, if at all. A credit rating downgrade, particularly to sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities, potentially significantly increasing our cost of capital and other associated operating costs which may not be recoverable through existing regulatory rate structures and contracts with customers.

Our use of derivative financial instruments as hedges against commodity prices and financial market risks could result in material financial losses.

We use various financial and physical derivatives, including futures, forwards, options and swaps to manage commodity price and interest rate risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP does not always match up with the gains or losses on the commodities being hedged. For Black Hills Energy Services under the Choice Gas Program, and in certain instances within our regulated Utilities where unrealized and realized gains and losses from derivative instruments are not approved for regulatory accounting treatment, fluctuating commodity prices may cause fluctuations in reported financial results due to mark-to-market accounting treatment.

To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.

Additionally, our exchange-traded futures contracts are subject to futures margin posting requirements. To the extent we are unable to meet these requirements, this could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or may require us to increase our level of debt. Further, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability.

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We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments are dependent upon cash distributions to the holding company from the subsidiaries.

There is no assurance as to the amount, if any, of future dividends to the holding company because these subsidiaries depend on our future earnings, capital requirements and financial condition and are subject to declaration by the Board of Directors. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 9 of our Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.

We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.

Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers. Additionally insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. A loss for which we are not adequately insured could materially affect our financial results. The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient to cover all liabilities to which the Company may be subject, including liability and losses associated with wildfire, natural gas and gas storage field explosions, cyber-security breaches, environmental hazards and natural disasters.

Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and other postretirement benefit plans.

Assumptions related to interest rates, expected return on investments, mortality and other key actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. An adverse change to key assumptions associated with our defined benefit retirement plans may require significant unplanned contributions to the plans which could adversely affect our financial operating results including earnings, cash flow and liquidity.

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Costs associated with our healthcare plans and other benefits could increase significantly.

The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have required, and likely will continue to require, changes to our current employee benefit plans and supporting administrative processes. Our electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there is no assurance that the state utility commissions will allow recovery of these increased costs. The rising employee benefit costs, or inadequate recovery of such costs, may adversely affect our financial operating results including earnings, cash flow, or liquidity.

PANDEMIC RISK

Our business operations, results of operations, financial condition and cash flows could be adversely affected by the coronavirus (COVID-19) pandemic.

We have responded to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.

For the year ended December 31, ~~2018, which was filed with~~2020, the ~~SEC~~COVID-19 pandemic had a limited net financial impact on ~~February 19, 2019.~~our business operations, financial condition and cash flows. In particular, we experienced:

~~Segment information does not include intercompany eliminations~~•Increased allowance for credit losses and ~~all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.~~

~~Results of Operations~~

~~Consolidated Summary and Overview~~

For the Years Ended December 31,
2019 2018 2017
(in millions, except per diluted share amounts) Income EPS Income EPS Income EPS

Net income from continuing operations available for common stock $ 199.3
$ 3.28
$ 265.3
$ 4.78
$ 194.1
$ 3.52
Net (loss) from discontinued operations —
—
(6.9 ) (0.12 ) (17.1 ) (0.31 )
Net income available for common stock $ 199.3
$ 3.28
$ 258.4
$ 4.66
$ 177.0
$ 3.21

~~2019 Compared to 2018~~

~~The variance to the prior year included the following:~~

~~Electric Utilities’ adjusted operating income increased $4.4 million~~bad debt expense due to ~~reduced purchased power capacity~~anticipated customer non-payment as a result of suspended disconnections;

•Increased costs ~~increased rider revenues~~due to sequestration of mission-critical and ~~the prior year Wyoming Electric PCA settlement~~essential employees;

•Lower commercial and certain transport volumes partially offset by higher ~~operating expenses driven by~~electric and natural gas residential usage;

•Waived customer late payment fees;

•Reduced availability of our employees;

•Increased costs for personal protection equipment and cleaning supplies;

•Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;

•Minimal impacts to the availability of our contractors;

•Minimal decline in the funded status of our pension plan;

•Minimal interest expense increase due to disruptions in the Commercial Paper markets; and

•Reduced training, travel, and outside services related expenses.

Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business operations, financial condition and ~~employee costs;~~cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:

~~Gas Utilities’ adjusted operating income increased $4.7 million primarily due~~

•Adverse impacts on our strategic business plans, growth strategy and capital investments;

•Increased adverse impacts to ~~new customer rates~~electricity and ~~rider revenues, customer growth~~natural gas demand from our customers, particularly from commercial and ~~increased transport and transmission driven by increased volumes from new and existing customers partially offset by higher operating expenses driven by outside services and employee costs;~~industrial customers;

Power Generation’s adjusted operating income increased $2.2 million primarily due to higher revenue from increased wind MWh sold and higher PPA pricing partially offset by higher depreciation and property taxes from new wind assets;

~~Mining’s adjusted operating income decreased $3.7 million primarily due to lower tons sold driven by planned and unplanned generating facility outages partially offset by lower operating expenses;~~

~~Corporate and Other expenses decreased $1.4 million primarily due to prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations;~~

~~A $20 million pre-tax non-cash impairment in 2019 of our investment in equity securities of a privately held oil and gas company;~~

~~We expensed $5.4 million of development costs related to projects we no longer intend to construct; and~~

Increased tax expense of $53 million primarily due to a prior year $73 million tax benefit resulting from legal entity restructuring partially offset by a prior year $4.0 million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes and current year $5.9 million federal PTCs and related state ITCs associated with new wind assets.

~~2018 Compared to 2017~~

~~The variance when comparing 2018 to 2017 included the following:~~

Electric Utilities’ adjusted operating income decreased $21.9 million due to TCJA benefits delivered to customers, the Wyoming Electric PCA settlement and higher operating expenses partially offset by increased rider revenues and favorable weather;

Gas Utilities’ adjusted operating income increased $0.1 million primarily due to colder winter weather, new customer rates, customer growth and increased transport and transmission offset by TCJA benefits delivered to customers and higher operating expenses;

~~Power Generation’s adjusted operating income decreased $4.1 million primarily due to a decrease in MWh sold and higher operating expenses;~~

~~Mining’s adjusted operating income increased $2.8 million primarily due to increase in price per ton sold and lower operating expenses;~~

~~Corporate and Other expenses decreased $3.3 million primarily due to prior year acquisition costs; and~~

~~Increased tax benefit of $97 million primarily due to a $73 million tax benefit resulting from legal entity restructuring and a~~•Further reduction in the ~~federal corporate income~~availability of our employees and contractors;

•Increased costs as a result of our preventative measures, such as sequestration of essential employees and facility cleaning services;

•Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;

•Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax ~~rate~~credits and triggering potential damages under our power purchase agreements;

•Deterioration of the credit quality of our counterparties, including gas commodity contract counterparties, power purchase agreement counterparties, contractors or retail customers, that could result in credit losses;

•Impairment of goodwill or long-lived assets;

•Adverse impacts on our ability to construct and operate facilities;

•Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;

•Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;

•Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;

•Adverse impact on our liquidity position and cost of and ability to access funds from ~~35%~~financial institutions and capital markets; and

•Delays in our ability to ~~21%~~change rates through regulatory proceedings.

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To date, we have experienced limited impacts to our results of operations, financial condition, cash flows or business plans. However, the situation remains fluid and it is difficult to predict with certainty the potential impact of COVID-19 on our results of operations, financial condition and cash flows.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 3.LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 3, “Commitments, Contingencies and Guarantees”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

ITEM 4. MINE SAFETY DISCLOSURES

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

Linden R. Evans, age 58, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer — Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 19 years of experience with the Company.

Scott A. Buchholz, age 59, has been our Senior Vice President of Strategic Initiatives since July 2020. He served as Senior Vice President — Chief Information Officer from the ~~TCJA, effective~~closing of the Aquila Transaction in 2008 to 2020. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 40 years of experience with the Company, including 28 years with Aquila. Mr. Buchholz plans to retire on March 8, 2021.

Brian G. Iverson, age 58, has been Senior Vice President, General Counsel and Chief Compliance Officer since August 26, 2019. He served as Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary from February 1, 2019 to August 26, 2019, Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 17 years of experience with the Company.

Richard W. Kinzley, age 55, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 21 years of experience with the Company.

Jennifer C. Landis, age 46, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January ~~1, 2018.~~2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 19 years of experience with the Company.

Stuart Wevik, age 59, has been Senior Vice President - Utility Operations since August 26, 2019. He served as Group Vice President - Electric Utilities from 2016 to August 2019, Vice President - Utility Operations from 2008 to 2016, Vice President - Operations from 2004 to 2008 and Vice President and General Manager from 2003 to 2004. Mr. Wevik has 35 years of experience with the Company.

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PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of January 31, 2021, we had 3,537 common shareholders of record and 46,737 beneficial owners, representing all 50 states, the District of Columbia and 6 foreign countries.

We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 27, 2021 meeting, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend rate of $2.26 per share. This equivalent rate, if declared and paid in 2021, will represent 51 consecutive years of annual dividend increases.

UNREGISTERED SECURITIES ISSUED

There were no unregistered securities sold during 2020.

ISSUER PURCHASES OF EQUITY SECURITIES

The following table ~~summarizes select financial results by operating segment and details significant items (in thousands):~~contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2020:

For the Years Ended December 31,
2019 Variance 2018 Variance 2017
(in thousands)
Revenue
Revenue $ 1,885,669
$ (11,573 ) $ 1,897,242
$ 83,721
$ 1,813,521
Intercompany eliminations (150,769 ) (7,795 ) (142,974 ) (9,719 ) (133,255 )
$ 1,734,900
$ (19,368 ) $ 1,754,268
$ 74,002
$ 1,680,266

Adjusted operating income ^(a)

Electric Utilities $ 160,297
$ 4,428
$ 155,869
$ (21,868 ) $ 177,737
Gas Utilities 189,971
4,732
185,239
134
185,105
Power Generation 44,779
2,165
42,614
(4,076 ) 46,690
Mining 12,627
(3,713 ) 16,340
2,840
13,500
Corporate and Other (1,632 ) 1,393
(3,025 ) 3,271
(6,296 )
406,042
9,005
397,037
(19,699 ) 416,736

Interest expense, net (137,659 ) 2,316
(139,975 ) (2,873 ) (137,102 )
Impairment of investment (19,741 ) (19,741 ) —
—
—
Other income (expense), net (5,740 ) (4,560 ) (1,180 ) (3,288 ) 2,108
Income tax benefit (expense) (29,580 ) (53,247 ) 23,667
97,034
(73,367 )
Income from continuing operations 213,322
(66,227 ) 279,549
71,174
208,375
(Loss) from discontinued operations, net of tax —
6,887
(6,887 ) 10,212
(17,099 )
Net income 213,322
(59,340 ) 272,662
81,386
191,276
Net income attributable to noncontrolling interest (14,012 ) 208
(14,220 ) 22
(14,242 )
Net income available for common stock $ 199,310
$ (59,132 ) $ 258,442
$ 81,408
$ 177,034



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs









October 1, 2020 - October 31, 2020	1	$	53.95	—	—
November 1, 2020 - November 30, 2020	804	58.63		—	—
December 1, 2020 - December 31, 2020	7,569	59.66		—	—
Total	8,374	$	59.56	—	—

_____________


~~(a)~~	~~In 2019, we changed our measure of segment performance to adjusted operating income, which impacted our segment disclosures for all periods presented. See~~ ~~Note 5~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.~~

(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.

~~2019 Overview~~

ITEM 6.SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Summary

We are a customer-focused, growth-oriented electric and natural gas utility company with a mission of ~~Business Segments~~Improving Life with Energy and ~~Corporate Activity~~

a vision to be the Energy Partner of Choice. The Company provides electric and natural gas utility service to 1.3 million customers over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. We conduct our business operations through four reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. The Company conducts its utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. The Company’s Electric Utilities are supported by our Power Generation and Mining segments, which are mostly contracted to company affiliates and subject to utility-like regulation and oversight. The Power Generation segment produces electric power from its five generating facilities and sells most of the electric capacity and energy to our Electric Utilities under mid- and long-term contracts. The Mining segment, consisting of a single coal mine near Gillette, Wyoming, sells nearly all production to fuel the five on-site, mine-mouth power generation facilities. With more than 90% of the Company’s assets directly invested in its regulated utility businesses and the Power Generation and Mining segments supporting its electric utilities mainly through long-term contracts, the Company considers itself a domestic, pure-play electric and natural gas utility company.

OnThe Company has provided energy and served customers for 137 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. Our strategic focus has not changed in over a century - serving customers with affordable, reliable and safe energy and being strong environmental stewards. Our strategy today continues that emphasis on serving customers and being responsive to the people and communities we serve. Customer expectations are rapidly changing with the advancement of technology and customers are demanding simpler, faster and more convenient solutions to their energy needs. Customers and other stakeholders are demanding cleaner energy solutions to address concerns around carbon emissions. In this rapidly changing energy environment, we are Ready to serve.

Our strategy focuses on improving the way we serve customers with safe, reliable, affordable and cleaner energy while improving the lives of the customers and communities we serve. Our emphasis is on consistently outperforming utility industry averages in key safety metrics; transforming the customer experience; growing our electric and natural gas customer load; pursuing operating efficiencies; and modernizing utility infrastructure. These areas of focus will present the company with significant investment needs as we modernize 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 interactions.

Key Elements of our Business Strategy

Modernize, replace and operate utility infrastructure to meet our customers’ energy needs while providing safe, reliable, affordable and cleaner energy. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that spans nearly 1,600 miles of the United States. Our Electric Utilities own and operate 992 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 this utility infrastructure to meet customers’ and communities’ varied energy needs, ensure the continued delivery of safe, reliable and affordable energy and reduce GHG emission intensity. In addition, we invest in the accessibility, 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, our Electric Utilities utilize a distribution integrity program to ensure the timely repair and replacement of aging infrastructure. 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. All but one of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments which reflect the cost incurred in repairing and replacing the gas delivery systems.

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As of December ~~13, 2019,~~31, 2020, we estimate our five-year capital investment to be approximately $2.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure and to support customer and community growth needs. Our actual 2020 and forecasted capital expenditures and depreciation for the next five years from 2021 through 2025 are as follows (in millions):


	Actual		Forecasted
Capital Expenditures By Segment (a) :	2020		2021		2022		2023		2024		2025
(in millions)
Electric Utilities	$	271	$	240	$	180	$	143	$	156	$	154
Gas Utilities	449		377		347		339		330		326
Power Generation	9		10		9		6		4		5
Mining	8		9		9		9		9		10
Corporate and Other	18		11		5		13		13		13
Total	$	755	$	647	$	550	$	510	$	512	$	508

____________________________

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•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.

Proactively integrate 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 25% reduction from our Electric Utilities. Colorado Electric ~~issued~~has achieved an approximate 50% reduction in GHG emissions since 2005 and is on track to reach 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, 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 agency 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. Supporting our renewable energy efforts in Colorado, in September 2020, Colorado Electric received approval from the CPUC for its request for ~~proposals for~~approval of its preferred solar bid in support of its Renewable Advantage program, which plans to ~~potentially~~ add up to 200 MW of renewable energy by the end of 2023.

To date, many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to ~~its southern Colorado system. A competitive solicitation process~~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 ~~addition~~use of ~~cost-effective, utility-scale~~ renewable energy ~~projects includes wind, solar~~or the reduction of GHG emissions will likely drive the need for significant investment in our Electric Utilities and ~~battery storage to supplement existing~~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 ~~wind~~affordable 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.

Build and maintain strong relationships with wholesale power customers of our utilities and our power generation business. We strive to build strong relationships with other utilities, municipalities and wholesale customers. We believe we will continue to be an important provider of electricity to wholesale utility customers, who will continue to need products such as capacity and energy to reliably serve their customers. By providing these products under long-term contracts, we help our customers meet their energy needs. We also earn more stable revenues and greater returns for shareholders over the long-term than we would by selling energy into more volatile energy spot markets. In addition, relationships that we have established with wholesale power ~~supplies Bidders~~customers have ~~until February 15, 2020,~~developed into other opportunities. MEAN, MDU and the City of Gillette, Wyoming were wholesale power customers that are now joint minority owners in two of our power plants, Wygen I and Wygen III, reducing risk and providing steady revenues.

Vertically integrate businesses that are supportive of our Electric and Gas Utility businesses. While our primary focus is serving customers and growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to ~~submit proposals,~~our utilities. We currently own and operate power generation and mining assets that are vertically integrated into and support our Electric Utilities. These operations are located at our utility-generating complexes and are physically integrated into our Electric Utilities’ operations.

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The Power Generation segment currently owns five power facilities, four of which ~~will be reviewed by~~are contracted with our affiliate Electric Utilities under mid- to long-term power purchase agreements. Our Power Generation segment has an ~~independent evaluator overseen by the CPUC. Based on the outcome~~experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed 22 generation projects since 1995 with an aggregate investment in excess of $2.5 billion. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the ~~bidding process, projects would~~company’s generation assets. In certain states, our Electric Utilities are required to competitively bid for generation resources needed to serve customers. Generally, our Power Generation segment submits bids in response to those competitive solicitations. Our Power Generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs.

~~In July 2019, South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready program and related jointly-filed CPCN~~$1.00 per MMBtu, providing very cost competitive fuel to construct Corriedale. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric received approval from the SDPUC to increase the offering under the program by 12.5 MW. The two electric utilities also received a determination from the WPSC to increase the project to 52.5 MW. The $79 million project is expected to be in service by year-end 2020.

On September 17, 2019, South Dakota Electric completed construction on the final 94-mile segment of a 175-mile electric transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018, and the second 33-mile segment was placed in service on November 20, 2018.

~~Colorado Electric set a new all-time and summer peak load:~~

~~On July 19, 2019, Colorado Electric set a new all-time and summer peak load of 422 MW, exceeding the previous peak of 413 MW set in June 2018.~~

~~Wyoming Electric set a new all-time and summer peak load, and also set a new winter peak load:~~

~~On July 19, 2019, Wyoming Electric set a new all-time and summer peak load of 265 MW, exceeding the previous peak of 254 MW set in July 2018.~~

~~On December 16, 2019, Wyoming Electric set a new winter peak load of 247 MW, exceeding the previous peak of 238 MW set in December 2018.~~

~~Cooling degree days for the year ended December 31, 2019 were 14% higher than the normal~~our power plants when compared to ~~29% higher than normal in 2018.~~other coal-fired and natural gas-fired generating facilities. Nearly all of the mine’s production is sold to the five on-site, mine-mouth 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.

~~Heating degree days~~Grow our dividend. We are extremely proud of our track record of annual dividend increases for shareholders. 2020 represented our 50th consecutive year of increasing dividends. In January 2021, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend of $2.26 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. We require access to the ~~year ended December 31, 2019 were 5% higher than normal compared~~capital markets to ~~3% higher than normal in 2018.~~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.

~~Gas Utilities~~

~~Gas Utilities continued to consolidate utility jurisdictions within the States of Colorado, Nebraska, and Wyoming:~~

◦

On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. A new, single statewide rate structure will be effective March 1, 2020. New rates are expected to generate $13 million in new revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.

◦

On February 1, 2019, Colorado Gas submitted a rate review with the CPUC to consolidate rates, tariffs and services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and recommending a rate decrease. Colorado Gas has filed exceptions to the ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 and completed in early 2019.


◦	On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two natural gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services.

On December 1, 2019, Wyoming Gas placed in service the $54 million, 35-mile Natural Bridge pipeline project to enhance supply reliability and delivery capacity for customers in central Wyoming. The new 12-inch steel pipeline interconnects from a supply point near Douglas, Wyoming, to facilities near Casper, Wyoming. The associated investment was included in the Wyoming Gas rate review completed in December 2019.

~~Heating degree days at the Gas Utilities for the year ended December 31, 2019 were 5% higher than normal compared to 2% higher than normal in 2018.~~

Power Generation

~~On November 26, 2019,~~Our Power Generation segment, which operates through Black Hills Electric Generation ~~placed~~and its subsidiaries, acquires, develops, constructs and operates our non-regulated power plants. As of December 31, 2020, we held varying interests in ~~service Busch Ranch II. Through~~independent power plants with a ~~competitive bidding process,~~total net ownership of 423 MW.

We produce electric power from our generating facilities and sell the electric capacity and energy, primarily to affiliates under a combination of mid- to long-term contracts, which mitigates the impacts of volatility in future power prices and fluctuations in demand.

As of December 31, 2020, the power plant ownership interests held by our Power Generation segment include:


Power Plants	Fuel Type	Location	Ownership Interest % (d)	Owned Capacity (MW)	In Service Date
Wygen I	Coal	Gillette, Wyoming	76.5%	68.9	2003
Pueblo Airport Generation (a)	Gas	Pueblo, Colorado	50.1%	200.0	2012
Busch Ranch I (b)	Wind	Pueblo, Colorado	50.0%	14.5	2012
Busch Ranch II (c)	Wind	Pueblo, Colorado	100.0%	60.0	2019
Top of Iowa (c)	Wind	Joice, Iowa	100.0%	80.0	2019
				423.4

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(b) In 2013, Busch Ranch I was ~~selected~~awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act.

(c) The Busch Ranch II and Top of Iowa facilities qualify for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date each facility was originally placed in service.

(d) Jointly owned facilities are discussed in Note 6 of the Notes to ~~deliver renewable~~Consolidated Financial Statements in this Annual Report on Form 10-K.

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Competition. The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess.

With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity and foster competition within the wholesale electricity markets. Our Power Generation business could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for IPPs in some regions. To date, these initiatives have not had a material impact on our Power Generation segment.

The Energy Policy Act of 1992 and Public Utility Holding Company Act of 2005 (PUHCA 2005). PUHCA 2005 reiterated the definition and benefits of Exempt Wholesale Generator (EWG) status. Under PUHCA 2005, an EWG is an entity or generator engaged, directly or indirectly through one or more affiliates, exclusively in the business of owning, operating or both owning and operating all or part of one or more eligible facilities and selling electric energy at wholesale. Though EWGs are public utilities within the definition set forth in the Federal Power Act and are subject to FERC regulation of rates and charges, they are exempt from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with three EWGs, Wygen I, Pueblo Airport Generating and Top of Iowa. Each of these three EWG’s have been granted market-based rate authority.

Operating statistics. See a summary of key operating statistics in the Power Generation segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

Mining

Our Mining segment operates a single coal mine through our WRDC subsidiary. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine near Gillette, Wyoming. The WRDC mine, which we acquired in 1956 from Homestake Mining Company, is located in the Powder River Basin. We produced approximately 3.7 million tons of coal in 2020.

Substantially all of the mine’s production is currently sold under contracts to:

•South Dakota Electric for use at the 90 MW Neil Simpson II plant to which we sell approximately 500,000 tons each year. This contract is for the life of the plant;

•Wyoming Electric for use at the 95 MW Wygen II plant to which we sell approximately 550,000 tons each year. This contract is for the life of the plant;

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•The 362 MW Wyodak Plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a ~~25-year PPA~~minimum of 1.5 million tons each year, subject to ~~Colorado Electric.~~adjustments for planned outages and other contract terms. This contract expires December 31, 2022 and negotiations to extend the contract are ongoing. South Dakota Electric is also obligated to purchase a minimum of 375,000 tons per year for its 20% share of the power plant, subject to adjustments for planned outages and other contract terms;

~~On August 2, 2019,~~•The 110 MW Wygen III power plant jointly owned 52% by South Dakota Electric, 25% by MDU and 23% by the City of Gillette to which we sell approximately 600,000 tons each year;

•The 90 MW Wygen I power plant jointly owned 76.5% by Black Hills Wyoming and 23.5% by MEAN to which we sell approximately 500,000 tons each year; and

•Certain regional industrial customers served by truck to which we sell a total of approximately 300,000 tons each year. These contracts have terms of one to five years.

Our Mining segment sells coal to South Dakota Electric and Wyoming Electric ~~jointly filed~~for all of their requirements under cost-based agreements that regulate earnings from these affiliate sales to a ~~request with FERC~~specified return on our mine’s cost-depreciated investment base. The return calculated annually is 400 basis points above Moody’s A-Rated Utility Bond Index applied to our Mining investment base.

The price of unprocessed coal sold to PacifiCorp for ~~approval of a new 60 MW PPA.~~the Wyodak Plant is determined by the supply agreement described above. The agreement ~~would fulfill~~included a price adjustment in 2019. The price adjustment essentially allowed us to retain the ~~capacity need for Wyoming Electric at the expiration~~full economic advantage of the ~~current~~mine’s location adjacent to the plant. The price adjustment was based on market price plus considerations for the avoided costs of rail transportation and an unloading facility, which PacifiCorp would have to incur if it purchased from another mine. In addition, the agreement also provided for the monthly escalation of price based on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.an escalation factor.

~~Mining~~

In October 2019, negotiations were completed for the price ~~reopener~~re-opener in the contract with the Wyodak ~~power plant. Effective July 1, 2019, the~~Plant. The new price was

reset at $17.94 per ton ~~with customary escalators,~~effective July 1, 2019, compared to the prior contract price of $18.25 per ton. The current contract ~~expires~~price is comprised of three components: 1) avoided transportation costs (approximately 20% of current price); 2) avoided costs of an unloading facility (approximately 30% of current price); and 3) a rolling 12-month average of the Coal Daily spot market price of 8,400 Btu Powder River Basin coal (approximately 50% of current price).

Additionally, coal competes with other energy sources, such as natural gas, wind, solar and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental and availability considerations affect the overall demand for coal as a fuel.

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Environmental Matters

Short-term Emission Limits. The EPA and State Air Quality Programs implemented short-term emission limits for coal and natural gas-fired generating units during normal and start-up operating scenarios for SO2, NOx and opacity. The limits pertain to emissions during start-up periods and upset conditions such as mechanical malfunctions. State and federal regulatory agencies typically excuse short-term emissions exceedances if they are reported and corrected immediately or if it occurs during start-up.

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For additional information, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Affordable Clean Energy Rule. The EPA was directed to repeal, revise and replace the Clean Power Plan rule. On August 31, 2018, the EPA published the proposed Affordable Clean Energy (ACE) rule. This rule focused on heat-rate improvements on coal-fired boiler units and applied only to our coal-fired plants. The Company’s coal-fired plants subject to the rule had implemented or planned to implement a majority of the efficiency requirements listed in the rule. On January 19, 2021, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit vacated the ACE rule. The court remanded the regulation regarding carbon dioxide emissions from existing power plants back to the EPA for reconsideration. Currently, there is no rule governing power plant GHG emissions and it is uncertain when a new rule will be promulgated.

OSM Coal Combustion Residual Rule (CCR). The EPA issued the CCR which is currently effective and establishes requirements to protect surface and groundwater from impacts of coal ash impoundments. WRDC is exempt from the EPA CCR because ash is used for backfill reclamation in areas previously mined. The Office of Surface Mining (OSM) was considering CCR rules that would apply to the mine, but these rules were not proposed during the Trump administration. We will continue to monitor to see if the Biden administration pursues these rules.

Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We assess risk annually and develop mitigation strategies to successfully and responsibly manage and ensure compliance across the enterprise. For additional information on environmental matters, see Item 1A and Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Other Properties

In addition to the properties previously disclosed in the sections above, we own or lease several facilities throughout our service territories including a corporate headquarters building and various office, service center, storage, shop and warehouse space. Substantially all of the tangible utility properties of South Dakota Electric and Wyoming Electric are ~~underway~~subject to ~~extend~~liens securing first mortgage bonds issued by South Dakota Electric and Wyoming Electric, respectively.

Human Capital Resources

Overview

Black Hills Corporation is committed to supporting operational excellence by attracting, motivating, retaining and encouraging the ~~contract.~~development of highly qualified employees. Our employees’ drive and dedication to their work, and their commitment to the safety of our customers and their fellow employees, allows Black Hills Corporation to successfully grow and manage our business year over year. The impacts of COVID-19 to our businesses and employees are discussed in the Company Highlights within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

~~Corporate~~

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Our Team			As of December 31, 2020
Total employees			3,011
Gender diversity (women as a % of total employees)			26%
Women in executive leadership positions (a)			31%
Ethnic diversity (non-white employees as a % of total)			11%
Military veterans			16%
Represented by a union			25%

			For the year ended December 31, 2020
Number of external hires			299
External hires gender diversity (as a % of total external hires)			29%
External hires ethnic diversity (as a % of total external hires)			16%
Turnover rate (b)			8%
Retirement rate			3%

__________

(a) Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.

(b) Includes voluntary and ~~Other~~involuntary separations, but excludes internships.

~~On October 3, 2019,~~Total Employees


			Number of Employees
			At December 31, 2020
Electric Utilities			379
Gas Utilities			1,237

Power Generation and Mining			60
Corporate and Other			1,335
Total			3,011

Collective Bargaining Agreements


Utility	Number of Employees	Union Affiliation	Expiration Date of Collective Bargaining Agreement
Colorado Electric	95	IBEW Local 667	April 15, 2023
South Dakota Electric	137	IBEW Local 1250	March 31, 2022
Wyoming Electric	26	IBEW Local 111	June 30, 2024
Total Electric Utilities	258

Iowa Gas	121	IBEW Local 204	January 31, 2026
Kansas Gas	17	Communications Workers of America, AFL-CIO Local 6407	December 31, 2024
Nebraska Gas	100	IBEW Local 244	March 13, 2022
Nebraska Gas	147	CWA Local 7476	October 30, 2023
Wyoming Gas	15	IBEW Local 111	June 30, 2024
Wyoming Gas	84	CWA Local 7476	October 30, 2023
Total Gas Utilities	484

Total	742

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Attraction

Diversity & Inclusion

At Black Hills Corporation, we ~~completed~~believe in the benefits of diversity, equity and inclusion. We believe that a diverse workforce will assist us in achieving our goals of becoming the safest utility in the nation, providing exceptional customer service and achieving new levels of growth in a rapidly evolving industry. Workforce diversity trends, including diverse new hires, promotions and turnover, are monitored at regular intervals.

Development and Retention

ITEM 1A.RISK FACTORS

The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect the business operations, financial condition, results of operations or cash flows are described below. These risk factors, along with other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.

STRATEGIC RISKS

Our continued success is dependent on execution of our strategic business plans including our growth strategy.

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Customer growth and usage in our service territories may fluctuate with economic conditions, emerging technologies or responses to price increases.

Our financial operating results are impacted by energy demand in our service territories. Customer growth and usage may be impacted by a number of factors, including the voluntary reduction in consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, economic conditions impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us would decline. Such developments could affect the price of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Each of these factors could materially affect our financial operating results including earnings, cash flow and liquidity.

REGULATORY, LEGISLATIVE AND LEGAL RISKS

We own and operate regulated and unregulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase, store and deliver natural gas to our customers. These business activities are subject to evolving public ~~debt offering~~concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.

There is uncertainty surrounding climate regulation due to legal challenges to some current regulations and anticipated new federal and/or state climate legislation and regulation. The Biden administration has issued executive orders aimed at reducing GHG emissions and declared climate change a national security policy for the first time. New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of ~~$700 million~~additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or capacity reductions of coal-fired power generation facilities and potential increased production from our combined cycle natural gas-fired generating units. Increased rules and regulations associated with fossil fuels and GHG emissions could result in ~~senior unsecured notes. Proceeds were used~~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 ~~repay~~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 ~~$400 million Corporate term loan due June 17, 2021, retire~~effect of GHG legislation or regulation on our results of operations, financial condition or cash flows.

Future GHG constraints designed to minimize emissions from natural gas could likewise result in increased costs and affect the ~~$200 million 5.875% senior notes due July 15, 2020~~demand for natural gas as well as the prices charged to customers and ~~repay~~the competitive position of natural gas. Certain cities in our operational footprint are focused on electrification and have adopted initiatives to prohibit the construction of new natural gas distribution facilities. Any such initiatives and legislation could have a material impact on our results of operations, financial condition and cash flows.

We may be subject to unfavorable or untimely federal and state regulatory outcomes.

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Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements.

Legislative and regulatory requirements may lead to increased costs and result in compliance penalties.

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 ~~short-term~~our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. We regularly engage in negotiations on renewals of franchise agreements with our municipal governments. We have from time to time faced challenges or ballot initiatives on franchise renewals. To date, we have been successful in resolving or defending each of these challenges. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation. We also cannot quantify the impact that such action would have on the remainder of our business operations.

Changes in Federal tax law may significantly impact our business.

OPERATING RISKS

The risks associated with management of these operations include:

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•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;

•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;

and our results of operations;

•Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses; and

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Cyberattacks, terrorism, or other malicious acts targeting our key technology systems could disrupt our operations, or lead to a loss or misuse of confidential and proprietary information.

Weather conditions, including the impacts of climate change, may cause fluctuation in customer usage.

FINANCIAL RISKS

A sub-investment grade credit rating could impact our ability to access capital markets.

Our issuer credit rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. Reduction of our investment grade credit ratings could impair our ability to refinance or repay our existing debt and complete new financings on reasonable terms, if at all. A credit rating downgrade, particularly to sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities, potentially significantly increasing our cost of capital and other associated operating costs which may not be recoverable through existing regulatory rate structures and contracts with customers.

Our use of derivative financial instruments as hedges against commodity prices and financial market risks could result in material financial losses.

~~During~~

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We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments are dependent upon cash distributions to the holding company from the subsidiaries.

We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

National and regional economic conditions may cause increased counterparty credit risk, late payments and uncollectible accounts.

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.

Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and other postretirement benefit plans.

Assumptions related to interest rates, expected return on investments, mortality and other key actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to these plans. An adverse change to key assumptions associated with our defined benefit retirement plans may require significant unplanned contributions to the plans which could adversely affect our financial operating results including earnings, cash flow and liquidity.

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Costs associated with our healthcare plans and other benefits could increase significantly.

The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have required, and likely will continue to require, changes to our current employee benefit plans and supporting administrative processes. Our electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates we have generally recovered the cost of providing employee benefits. As benefit costs continue to rise, there is no assurance that the state utility commissions will allow recovery of these increased costs. The rising employee benefit costs, or inadequate recovery of such costs, may adversely affect our financial operating results including earnings, cash flow, or liquidity.

PANDEMIC RISK

Our business operations, results of operations, financial condition and cash flows could be adversely affected by the coronavirus (COVID-19) pandemic.

We have responded to the global pandemic of COVID-19 by taking steps to mitigate the potential risks to us posed by its spread.

For the year ended December 31, 2020, the COVID-19 pandemic had a limited net financial impact on our business operations, financial condition and cash flows. In particular, we experienced:

•Increased allowance for credit losses and bad debt expense due to anticipated customer non-payment as a result of suspended disconnections;

•Increased costs due to sequestration of mission-critical and essential employees;

•Lower commercial and certain transport volumes partially offset by higher electric and natural gas residential usage;

•Waived customer late payment fees;

•Reduced availability of our employees;

•Increased costs for personal protection equipment and cleaning supplies;

•Minimal disruptions receiving the materials and supplies necessary to maintain operations and continue executing our capital investment plan;

•Minimal impacts to the availability of our contractors;

•Minimal decline in the funded status of our pension plan;

•Minimal interest expense increase due to disruptions in the Commercial Paper markets; and

•Reduced training, travel, and outside services related expenses.

Should the COVID-19 pandemic continue for a prolonged period or impact the areas we serve more significantly than it has to date, our business operations, financial condition and cash flows could be impacted in more significant ways. In addition to exacerbating the impacts described above, we could experience:

•Adverse impacts on our strategic business plans, growth strategy and capital investments;

•Increased adverse impacts to electricity and natural gas demand from our customers, particularly from commercial and industrial customers;

•Further reduction in the availability of our employees and contractors;

•Increased costs as a result of our preventative measures, such as sequestration of essential employees and facility cleaning services;

•Delays and disruptions in the availability, timely delivery and cost of materials and components used in our operations;

•Disruptions in the commercial operation dates of certain projects impacting qualification criteria for certain tax credits and triggering potential damages under our power purchase agreements;

•Impairment of goodwill or long-lived assets;

•Adverse impacts on our ability to construct and operate facilities;

•Inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding Consolidated Indebtedness to Capitalization Ratio;

•Deterioration in our financial metrics or the business environment that adversely impacts our credit ratings;

•Delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start dates of construction;

•Adverse impact on our liquidity position and cost of and ability to access funds from financial institutions and capital markets; and

•Delays in our ability to change rates through regulatory proceedings.

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ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 3.LEGAL PROCEEDINGS

ITEM 4. MINE SAFETY DISCLOSURES

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

Linden R. Evans, age 58, has been President and Chief Executive Officer since January 1, 2019, ~~we issued~~President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer — Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 19 years of experience with the Company.

Scott A. Buchholz, age 59, has been our Senior Vice President of Strategic Initiatives since July 2020. He served as Senior Vice President — Chief Information Officer from the closing of the Aquila Transaction in 2008 to 2020. Prior to joining the Company, he was Aquila’s Vice President of Information Technology from 2005 until 2008, Six Sigma Deployment Leader/Black Belt from 2004 until 2005, and General Manager, Corporate Information Technology from 2002 until 2004. Mr. Buchholz has 40 years of experience with the Company, including 28 years with Aquila. Mr. Buchholz plans to retire on March 8, 2021.

Jennifer C. Landis, age 46, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 19 years of experience with the Company.

Erik Keller, age 57, joined the Company as Senior Vice President and Chief Information Officer on July 27, 2020. Prior to joining the company, he was an Information Technology consultant to Ontic Inc., a ~~total~~global provider of ~~1.3 million shares of~~parts and services for legacy aerospace platforms, from January 2020 to July 2020, and Chief Information Officer for BBA Aviation, a global aviation support and aftermarket services provider, from February 2012 to January 2020.

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PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for ~~net proceeds~~the foreseeable future. At its January 27, 2021 meeting, our Board of ~~$99 million under~~Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend rate of $2.26 per share. This equivalent rate, if declared and paid in 2021, will represent 51 consecutive years of annual dividend increases.

For additional discussion of our ~~ATM equity offering program.~~

~~On June 17, 2019, we amended~~dividend policy and factors that may limit our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were usedability to pay ~~down short-term debt. Proceeds from the October 3, 2019 debt transaction~~dividends, see “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.

UNREGISTERED SECURITIES ISSUED

There were ~~used to repay this term loan.~~no unregistered securities sold during 2020.

~~Operating Results~~ISSUER PURCHASES OF EQUITY SECURITIES

~~A discussion of operating results from our business segments follows.~~

~~Non-GAAP Financial Measure~~

The following ~~discussion includes~~table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2020:



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs









October 1, 2020 - October 31, 2020	1	$	53.95	—	—
November 1, 2020 - November 30, 2020	804	58.63		—	—
December 1, 2020 - December 31, 2020	7,569	59.66		—	—
Total	8,374	$	59.56	—	—

_____________

(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.SELECTED FINANCIAL DATA

We have early adopted the new SEC amendments to modernize, simplify, and enhance certain financial ~~information prepared~~disclosure requirements in ~~accordance~~Regulation S-K which, among other things, eliminates the requirement to present Selected Financial Data.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Summary

We are a customer-focused, growth-oriented electric and natural gas utility company with ~~GAAP,~~a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company provides electric and natural gas utility service to 1.3 million customers over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. We conduct our business operations through four reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as ~~well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure~~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’s Electric Utilities are supported by our Power Generation and Mining segments, which are mostly contracted to company affiliates and subject to utility-like regulation and oversight. The Power Generation segment produces electric power from its five generating facilities and sells most of the electric capacity and energy to our Electric Utilities under mid- and long-term contracts. The Mining segment, consisting of a ~~company’s financial performance, financial position or~~single coal mine near Gillette, Wyoming, sells nearly all production to fuel the five on-site, mine-mouth power generation facilities. With more than 90% of the Company’s assets directly invested in its regulated utility businesses and the Power Generation and Mining segments supporting its electric utilities mainly through long-term contracts, the Company considers itself a domestic, pure-play electric and natural gas utility company.

The Company has provided energy and served customers for 137 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. Our strategic focus has not changed in over a century - serving customers with affordable, reliable and safe energy and being strong environmental stewards. Our strategy today continues that emphasis on serving customers and being responsive to the people and communities we serve. Customer expectations are rapidly changing with the advancement of technology and customers are demanding simpler, faster and more convenient solutions to their energy needs. Customers and other stakeholders are demanding cleaner energy solutions to address concerns around carbon emissions. In this rapidly changing energy environment, we are Ready to serve.

Key Elements of our Business Strategy

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, our Electric Utilities utilize a distribution integrity program to ensure the timely repair and replacement of aging infrastructure. 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. All but one of our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments which reflect the cost incurred in repairing and replacing the gas delivery systems.

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As of December 31, 2020, we estimate our five-year capital investment to be approximately $2.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure and to support customer and community growth needs. Our actual 2020 and forecasted capital expenditures and depreciation for the next five years from 2021 through 2025 are as follows (in millions):


	Actual		Forecasted
Capital Expenditures By Segment (a) :	2020		2021		2022		2023		2024		2025
(in millions)
Electric Utilities	$	271	$	240	$	180	$	143	$	156	$	154
Gas Utilities	449		377		347		339		330		326
Power Generation	9		10		9		6		4		5
Mining	8		9		9		9		9		10
Corporate and Other	18		11		5		13		13		13
Total	$	755	$	647	$	550	$	510	$	512	$	508

____________________________

(a) Includes accruals for property, plant and equipment as disclosed as supplemental cash ~~flows~~flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements in this Annual Report on Form 10-K.

Efficiently plan, construct and operate rate base power generation facilities to serve our Electric Utilities. We believe that ~~excludes (or includes) amounts~~we best serve customers and communities with a vertically integrated business model for our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to cost-effectively supply electricity to our customers. We strive to provide power at reasonable rates to our customers and earn competitive returns for our investors.

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•When generating assets are included in ~~(or excluded from)~~ the ~~most directly comparable measure calculated~~utility rate base and ~~presented~~reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in ~~accordance with GAAP. Gross margin (revenue less~~the long run; especially when compared to power otherwise purchased from the open market through wholesale contracts that are periodically re-priced to reflect current and varying market conditions;

•Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;

•The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of ~~sales) is~~capital; and

•Investors are provided a ~~non-GAAP financial measure due~~long-term and stable return on their investment.

Proactively integrate alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. In November 2020, we announced clean energy goals to ~~the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.~~

~~Gross margin~~reduce GHG emissions intensity for our Electric Utilities ~~is calculated as operating revenue less cost~~ of ~~fuel~~40% by 2030 and ~~purchased power. Gross margin~~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 25% reduction from our Electric Utilities. Colorado Electric has achieved an approximate 50% reduction in GHG emissions since 2005 and is ~~calculated as operating revenues less~~on track to reach 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 ~~gas sold. Our gross margin~~our decision-making, which is ~~impacted~~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, 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 agency 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. Supporting our renewable energy efforts in Colorado, in September 2020, Colorado Electric received approval from the CPUC for its request for approval of its preferred solar bid in support of its Renewable Advantage program, which plans to add up to 200 MW of renewable energy by the ~~fluctuations~~end of 2023.

To date, 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 affordable 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.

Vertically integrate businesses that are supportive of our Electric and Gas Utility businesses. While our primary focus is serving customers and growing our core utilities, we selectively invest in vertically integrated businesses that provide cost effective and efficient fuel and energy to our utilities. We currently own and operate power generation and mining assets that are vertically integrated into and support our Electric Utilities. These operations are located at our utility-generating complexes and are physically integrated into our Electric Utilities’ operations.

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The Power Generation segment currently owns five power facilities, four of which are contracted with our affiliate Electric Utilities under mid- to long-term power purchase agreements. Our Power Generation segment has an experienced staff with significant expertise in planning, building and operating power plants. The power generation team has constructed 22 generation projects since 1995 with an aggregate investment in excess of $2.5 billion. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the company’s generation assets. In certain states, our Electric Utilities are required to competitively bid for generation resources needed to serve customers. Generally, our Power Generation segment submits bids in response to those competitive solicitations. Our Power Generation segment can often realize competitive advantages provided by prior construction expertise, fuel supply advantages and by co-locating new plants at existing sites, reducing infrastructure and operating costs.

Our small surface coal mine is located immediately adjacent to our Gillette energy complex in northeastern Wyoming, where all five of our remaining coal-fired power plants are located. We operate and own majority interests in four of the five power plants. We own 20% of the fifth power plant which is operated by a majority owner. The mine provides low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our power plants when compared to other coal-fired and natural gas-fired generating facilities. Nearly all of the mine’s production is sold to the five on-site, mine-mouth 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.

Grow our dividend. We are extremely proud of our track record of annual dividend increases for shareholders. 2020 represented our 50th consecutive year of increasing dividends. In January 2021, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend of $2.26 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 50% to 60%.

Maintain an investment grade credit rating and ready access to debt and equity capital markets. We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings-accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating.

Prospective Information

We expect to generate long-term growth through the expansion of integrated utilities and supporting operations. Sustained growth requires continued capital deployment. Our integrated energy portfolio, focused predominately on regulated utilities, provides growth opportunities, yet avoids concentrating business risk. We expect much of our earnings growth in the next few years will come from the need for capital deployment at our utilities and continued focus on improving efficiencies and controlling costs. Although dependent on market conditions, we are confident in our ability to obtain additional financing, as necessary, to continue our growth plans. We remain focused on prudently managing our operations and maintaining our overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plan. Prospective information for our operating segments should be read in conjunction with our business strategy discussed above, and our company highlights discussed below.

Company Highlights

February 2021 Weather Event

In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. Although this historic weather and energy demand event strained energy resources across the United States, our natural gas and electric systems performed as expected and demonstrated our Ready to Serve commitment to our customers. Our ongoing system investments in safety and reliability and our strong operational performance were essential in our ability to maintain service for our customers during this extraordinary event.

We responded to this event with requests for certain natural gas customer usage curtailments that began on February 12, 2021, and extended through February 19, 2021, to ensure the reliability of our system. We also communicated to all customers on how to conserve energy and stay safe during this event. Our customer service representatives worked extended hours to provide guidance and support to our customers.

Our Utilities have regulatory mechanisms to recover the increased energy costs from this record-breaking cold weather event. However, given the extraordinary impact of these higher costs to our customers, we expect our regulators to undertake a heightened review. We are engaged with our regulators to identify appropriate recovery periods over which to recover costs associated with this event as we continue to address the impacts to our customers’ bills.

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As a result of this historic event, our natural gas purchases increased by approximately $600 million compared to forecasted base load for the month of February. This amount is a preliminary estimate through February 24, 2021, and does not include certain pipeline transportation charges that remain subject to settlement and are payable in late March 2021. To fund February natural gas purchases and ~~other fuel supply costs. However, while these fluctuating costs impact gross margin~~pipeline transportation charges and provide additional liquidity, we entered into an $800 million term loan maturing on November 23, 2021. The nine-month term loan has no prepayment penalty and is subject to the same covenants as our Revolving Credit Facility. We expect to repay a ~~percentage~~portion of ~~revenue, they only impact total gross margin if~~this term loan prior to maturity and refinance the ~~costs cannot be passed through~~remaining portion in longer-term debt.

As of February 24, 2021, the Company had $1.3 billion of liquidity consisting of approximately $800 million of cash and $500 million of available capacity on its Revolving Credit Facility.

COVID-19 Pandemic

One of the Company’s core values is safety. The COVID-19 pandemic has given us an opportunity to demonstrate our commitment to the health and safety of our customers, employees, business partners and the communities we serve. We have executed our business continuity plans across all of our jurisdictions with the goal of continuing to provide safe and reliable service during the COVID-19 pandemic.

For the year ended December 31, 2020, we have experienced limited impacts to our ~~customers.~~financial results and operational activities due to COVID-19. Negative impacts to gross margins were driven primarily by lower volumes in certain commercial and industrial customers and waived customer late payment fees which were partially offset by higher residential usage. Increased operations and maintenance expenses due to sequestration costs of mission critical and essential employees and increased bad debt expense were partially offset by decreased training, travel, and outside services related expenses.

We continue to closely monitor customer loads in our states as updated executive orders and recommendations associated with COVID-19 are provided. We have continued to proactively communicate with various commercial and industrial customers in our service territories to understand their needs and forecast the potential financial implications. We have increased our allowance for credit losses and bad debt expense by $3.3 million for the year ended December 31, 2020, after considering the potential economic impact of the COVID-19 pandemic in forward looking projections related to write-off and recovery rates. All of our jurisdictions temporarily suspended disconnections for a period of time. State orders lifting those restrictions have been issued in nearly all of our jurisdictions; however, we expect the status of restrictions will continue to fluctuate for the next several months. We continue to monitor customer loads, accounts receivable arrears balances, disconnects, cash flows and bad debt expense. We are proactively working with customers to establish payment plans and find available payment assistance resources.

Throughout 2020, we maintained adequate liquidity to operate our businesses and fund our capital investment program. In February 2020, the Company issued $100 million in equity to support its 2020 capital investment program. In June 2020, the Company issued $400 million of long-term debt which was used to repay short-term debt and for working capital and general corporate purposes. For the year ended December 31, 2020, the Company also utilized a combination of its $750 million Revolving Credit Facility and CP Program to meet its funding requirements. As of December 31, 2020, the Company had $498 million of liquidity which included $6.4 million of cash and $491 million of available capacity on its Revolving Credit Facility. We continue to meet our debt covenant requirements. We also continue to monitor the funding status of our employee benefit plan obligations, which did not materially change during the year ended December 31, 2020.

We are monitoring supply chains, including lead times for key materials and supplies, availability of resources, and status of large capital projects. To date, there have been limited impacts from COVID-19 on supply chains including the availability of supplies, materials and lead times. Capital projects are ongoing without material disruption to schedules due to COVID-19. Our ~~gross margin measure~~third party resources continue to support our business plans without disruption. Contingency plans are ready to be executed if significant disruption to supply chain occurs; however, we currently do not anticipate a significant impact from COVID-19 on our capital investment plan for 2021.

We continue to work closely with local health, public safety and government officials to minimize the spread of COVID-19 and its impact to our employees and the services we provide to our customers. Actions the Company took earlier in the year included implementing protocols for our field operations personnel to safely and effectively interact with our customers, asking certain employees to work from home, requiring employees to complete daily health assessments, covering 100% of COVID-19 testing costs for our active employee medical plans, limiting travel to only mission-critical purposes and temporarily sequestering essential employees.

During the third quarter of 2020, we suspended sequestration of essential employees but continued to monitor the impacts of COVID-19 in our service territories to ensure we provide reliable service to our customers. Additionally, we implemented our Ready2Return program, which includes a phased return of our employees to our work facilities while keeping our workforce healthy, safe and informed. Our Ready2Return program also focuses on enhancing our facility readiness to improve ventilation, ensure social distancing and establish cleaning services to reduce the spread of infection.

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On January 13, 2021, the FERC sent a letter to the Centers for Disease Control and Prevention’s (CDC) Advisory Committee on Immunization Practices urging that essential employees of the energy workforce receive vaccines earlier than currently recommended. We continue to monitor guidance from the CDC to ensure our essential employees may ~~not~~receive the vaccine within a prioritized phase.

We provide periodic status updates and maintain ongoing dialogue with the regulatory commissions in our jurisdictions. We have worked with regulators in our service territories to preserve our right for deferred regulatory treatment for certain COVID-19 related costs and to seek recovery of these costs at a later date.

During these uncertain times, we remain highly focused on the safety and health of our customers, employees, business partners and communities. We continue to monitor load, customers’ ability to pay, the potential for supply chain disruption that may impact our capital and maintenance project plans, the availability of resources to execute our plans and the capital markets to ensure we have the liquidity necessary to support our financial needs.

As we look forward to 2021 and beyond, our operating results could be ~~comparable~~further affected by COVID-19, as discussed in detail in our Risk Factors.

Business Segment Highlights and Corporate Activity

Electric Utilities

•On November 30, 2020, South Dakota Electric and Wyoming Electric completed and placed in service the Corriedale project. The 52.5 MW wind project is jointly owned by the two electric utilities to ~~other companies’ gross margin measure. Furthermore,~~deliver renewable energy for large commercial, industrial and governmental agency customers under the Renewable Ready program.

•On October 15, 2020, the FERC approved a settlement agreement in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years.

•On September 23, 2020, Colorado Electric received approval from the CPUC for its request for approval of its preferred solar bid in support of its Renewable Advantage program. The program plans to add up to 200 MW of renewable energy in Colorado by the end of 2023.

•On July 10, 2020, Wyoming Electric set a new all-time peak load of 271 MW, surpassing the previous peak of 265 MW set in July 2019.

•On May 5, 2020, citizens in Pueblo, Colorado voted overwhelmingly to retain Colorado Electric as its electric utility provider by 75.6% of votes cast. The current franchise agreement continues through 2030.

Gas Utilities

•On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover significant infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates will be enacted on March 1, 2021 and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this ~~measure is not intended~~mechanism for consolidated utility alignment.

•On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to ~~replace operating income as determined~~implement new rates in the second quarter of 2021. On January 6, 2021 the CPUC issued an order dismissing the rate review. On January 26, 2021, Colorado Gas filed an application for rehearing, reargument or reconsideration in response to the Commission’s January 6 order.

On September 11, 2020, in accordance with ~~GAAP~~the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety and integrity focused investments in its system over five years. A decision from the CPUC is expected by mid-2021.

•On December 27, 2020, gas service to approximately 3,500 Colorado Gas customers in Aspen, Colorado was disrupted due to vandalism. Gas services were restored to nearly all customers by December 30, 2020 with the remaining few restored by January 1, 2021. Colorado Gas employees were joined by Black Hills Energy technicians from other states, as well as contractors and other utilities, to successfully restore service despite challenging weather, temperatures, additional precautions due to COVID-19 and significant travel by many to reach Aspen.

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•On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the new system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an ~~indicator~~annual revenue decrease of ~~operating performance.~~$0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020.

•On March 1, 2020, Wyoming Gas enacted new rates and implemented a new rider to recover integrity investments. The new, single statewide rate structure successfully completed the consolidation process of four natural gas utilities in the state and is expected to generate $13 million in new annual revenues. Going forward, the new rate structure and consolidated tariffs will contribute to improvements in customer service and reduce the complexity and number of rate reviews and other regulatory filings.

Power Generation

•On October 15, 2020, the FERC approved a settlement agreement in the joint application filed by Black Hills Wyoming and Wyoming Electric ~~Utilities~~

~~Operating results~~on August 2, 2019 for ~~the years ended December 31 for~~approval of a new 60 MW PPA. See additional information in the Electric Utilities ~~were as follows (in thousands):~~

2019 Variance 2018 Variance 2017

Revenue $ 712,752
$ 1,301
$ 711,451
$ 6,801
$ 704,650

Total fuel and purchased power 268,297
(15,543 ) 283,840
9,477
274,363

Gross margin (non-GAAP) 444,455
16,844
427,611
(2,676 ) 430,287

Operations and maintenance 195,581
9,406
186,175
13,868
172,307
Depreciation and amortization 88,577
3,010
85,567
5,324
80,243
Total operating expenses 284,158
12,416
271,742
19,192
252,550

Adjusted operating income ^(a)
$ 160,297
$ 4,428
$ 155,869
$ (21,868 ) $ 177,737

~~____________________~~


~~(a)~~	~~Due to the changes in our segment disclosures discussed in~~ Segment highlights above.~~Note 5~~ of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Electric Utilities Adjusted operating income was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in an increase of $6.4 million and $7.1 million, respectively.

~~2019 Compared to 2018~~

~~Gross margin~~ ~~increased over the prior year as a result of:~~

(in millions)
Reduction in purchased power capacity costs $ 6.5
Prior year Wyoming Electric PCA Stipulation settlement 3.7
Rider recovery 3.1
Increased commercial and industrial demand 1.9
Weather 0.2
Other 1.4
Total increase in Gross margin (non-GAAP) $ 16.8

~~Operations and maintenance expense~~ increased primarily due to $4.7 million of higher employee costs and $2.9 million of higher outside services expenses. Various other expenses comprise the remainder of the increase compared to the prior year.

~~Depreciation and amortization~~ ~~increased primarily due to higher asset base driven by prior and current year capital expenditures.~~

~~2018 Compared to 2017~~

~~Gross margin~~ ~~decreased over the prior year as a result of:~~

(in millions)
TCJA revenue reserve $ (22.3 )
Wyoming Electric PCA Stipulation settlement (2.6 )
Other (1.4 )
Horizon Point shared facility revenue ^(a)
9.8
Rider recovery 5.1
Weather 3.6
Power Marketing, transmission and Tech Services 3.5
Residential customer growth 1.6
Total increase (decrease) in Gross margin (non-GAAP) $ (2.7 )

~~____________________~~


~~(a)~~	~~Horizon Point shared facility revenue was offset by facility expenses at our operating segments and had no impact on consolidated results.~~

~~Operations and maintenance expense~~ increased primarily due to $4.5 million of higher facility costs, $4.1 million of higher outside services expenses, $3.6 million of higher employee costs, and $1.0 million of higher property taxes due to a higher asset base.

~~Depreciation and amortization~~ ~~increased primarily due to higher asset base driven by current and prior year capital expenditures.~~

For the year ended December 31,
Contracted power plant fleet availability ^(a)
2019 2018 2017

Coal-fired plants^(b)
92.1% 93.9% 88.9%
Natural gas fired plants and Other plants ^(c)
87.9% 96.4% 96.1%
Wind 95.6% 96.9% 93.3%
Total availability 89.9% 95.6% 93.6%

Wind capacity factor 38.7% 39.2% 36.7%

~~____________________~~


~~(a)~~	~~Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.~~


~~(b)~~	~~2019 included planned outages at Neil Simpson II and Wygen III and unplanned outages at Wyodak Plant and Wygen III.~~


~~(c)~~	~~2019 included planned outages at Neil Simpson CT and Lange CT.~~

~~Gas Utilities~~

~~Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):~~

2019 Variance 2018 Variance 2017
Revenue:
Natural gas - regulated $ 932,111
$ (10,813 ) $ 942,924
$ 77,093
$ 865,831
Other - non-regulated services 77,919
(4,464 ) 82,383
584
81,799
Total revenue 1,010,030
(15,277 ) 1,025,307
77,677
947,630

Cost of natural gas sold:
Natural gas - regulated 406,643
(35,887 ) 442,530
61,271
381,259
Other - non-regulated services 19,255
(368 ) 19,623
(8,721 ) 28,344
Total cost of sales 425,898
(36,255 ) 462,153
52,550
409,603

Gross margin (non-GAAP) 584,132
20,978
563,154
25,127
538,027

Operations and maintenance 301,844
10,363
291,481
22,291
269,190
Depreciation and amortization 92,317
5,883
86,434
2,702
83,732
Total operating expenses 394,161
16,246
377,915
24,993
352,922

Adjusted operating income $ 189,971
$ 4,732
$ 185,239
$ 134
$ 185,105

~~2019 Compared to 2018~~

~~Gross margin~~ ~~increased over the prior year as a result of:~~

(in millions)
New rates $ 16.2
Customer growth - distribution 5.2
Increased transport and transmission 2.6
Weather (2.2 )
Decreased mark-to-market on non-utility natural gas commodity contracts (3.3 )
Other 2.5
Total increase in Gross margin (non-GAAP) $ 21.0

~~Operations and maintenance expense~~ increased primarily due to $5.5 million of higher outside services expenses, $1.2 million higher employee costs and $2.0 million of higher property taxes due to a higher asset base driven by prior and current year capital expenditures. Various other expenses comprise the remainder of the increase compared to the prior year.

~~Depreciation and amortization~~ ~~increased primarily due to a higher asset base driven by prior and current year capital expenditures.~~

~~2018 Compared to 2017~~

~~Gross margin~~ ~~increased over the prior year as a result of:~~

(in millions)
Weather ^(a)
$ 13.8
New rates 10.7
Customer growth - distribution 5.2
Increased mark-to-market on non-utility natural gas commodity contracts 4.0
Increased transport and transmission 3.6
Natural gas volumes sold 3.2
Non-utility - Choice Gas, Tech Services and appliance repair 2.7
Other 2.4
TCJA revenue reserve (20.5 )
Total increase (decrease) in Gross margin (non-GAAP) $ 25.1

~~___________________~~


~~(a)~~	~~Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than normal compared to 10% lower than normal in 2017.~~

~~Operations and maintenance expense~~ increased primarily due to $11.8 million of higher employee costs, $4.7 million of higher facility costs, $4.0 million of higher outside services expenses and $2.1 million of higher bad debt expense driven by an increase in revenues.

~~Depreciation and amortization~~ ~~increased primarily due to higher asset base driven by prior and current year capital expenditures.~~

~~Power Generation~~

~~Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):~~

2019 Variance 2018 Variance 2017

Revenue $ 101,258
$ 8,807
$ 92,451
$ (2,169 ) $ 94,620

Total fuel 9,059
467
8,592
(748 ) 9,340
Operations and maintenance 28,429
3,294
25,135
2,093
23,042
Depreciation and amortization 18,991
2,881
16,110
562
15,548
Total operating expenses 56,479
6,642
49,837
1,907
47,930

Adjusted operating income ^(a)
$ 44,779
$ 2,165
$ 42,614
$ (4,076 ) $ 46,690

~~____________________~~


~~(a)~~	~~Due to the changes in our segment disclosures discussed in~~ ~~Note 5~~ of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Power Generation Adjusted operating income was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(5.7) million and $(6.5) million, respectively.

~~2019 Compared to 2018~~

Revenue increased in the current year due to increased wind MWh sold and higher PPA prices. Operating expenses increased in the current year primarily due to higher depreciation and property taxes from new wind assets.

~~2018 Compared to 2017~~

Revenue decreased in 2018 due to a decrease in MWh sold, primarily from a planned outage at Wygen I. Operating expenses increased due to higher maintenance expenses primarily related to outage costs at Wygen I and higher depreciation.

For the year ended December 31,
Contracted power plant fleet availability ^(a)
2019 2018 2017

Coal-fired plant ^(b)
94.5% 85.8% 96.9%
Natural gas-fired plants 98.6% 99.4% 99.2%
Wind ^(c)
90.6% N/A N/A
Total availability 95.0% 95.9% 98.6%

Wind capacity factor ^(c)
23.5% N/A N/A

~~___________~~


~~(a)~~	~~Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.~~


~~(b)~~	~~Wygen I experienced a planned outage in 2018~~


~~(c)~~	~~Change from 2018 to 2019 is driven by Black Hills Electric Generation’s acquisition of new wind assets.~~

~~Mining~~

~~Mining operating results for the years ended December 31 were as follows (in thousands):~~

2019 Variance 2018 Variance 2017

Revenue $ 61,629
$ (6,404 ) $ 68,033
$ 1,412
$ 66,621

Operations and maintenance 40,032
(3,696 ) 43,728
(1,154 ) 44,882
Depreciation, depletion and amortization 8,970
1,005
7,965
(274 ) 8,239
Total operating expenses 49,002
(2,691 ) 51,693
(1,428 ) 53,121

Adjusted operating income $ 12,627
$ (3,713 ) $ 16,340
$ 2,840
$ 13,500

~~The following table provides certain operating statistics for the Mining segment (in thousands):~~

2019 2018 2017
Tons of coal sold 3,716
4,085
4,183
Cubic yards of overburden moved 8,534
8,970
9,018
Coal reserves at year-end (in tons) 185,448
189,164
194,909

Revenue per ton $ 15.94
$ 16.11
$ 15.93

~~2019~~ ~~Compared to 2018~~

Current year revenue decreased primarily due to 9% fewer tons sold driven primarily by planned and unplanned generation facility outages at the Wyodak Plant. Operating expenses decreased primarily due to lower royalties and production taxes on decreased revenues and lower fuel, labor, and major maintenance expenses.

~~2018 Compared to 2017~~

Revenue increased primarily due to a 1% increase in price per ton sold. Current year revenue is also reflective of lease and rental revenue, previously reported in Other income, net. Operating expenses decreased primarily due to lower major maintenance expenses.

Corporate and Other

•On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. This forward sales option allows us to sell our shares through the ATM program at the current trading price without actually issuing any shares to satisfy the sale until a future date.

•On June 17, 2020, we completed a public debt offering of $400 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 2.50%, 10-year senior notes due June 15, 2030. The proceeds were used to repay short-term debt, as well as for working capital and general corporate purposes.

•On February 27, 2020, we issued 1.2 million shares of common stock at a price of $81.77 per share for net proceeds of $99 million.

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Results of Operations

Our discussion and analysis for the year ended December 31, 2020 compared to 2019 is included herein. For discussion and analysis for the year ended December 31, 2019 compared to 2018, 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, 2019, which was filed with the SEC on February 14, 2020.

Segment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Per share information references diluted shares unless otherwise noted.

Consolidated Summary and Overview


	For the Years Ended December 31,
	2020		2019		2018
	(in thousands)





Adjusted operating income (a) :
Electric Utilities	$	156,055	$	160,297	$	155,869
Gas Utilities	215,889		189,971		185,239
Power Generation	42,112		44,779		42,614
Mining	12,807		12,627		16,340
Corporate and Other	1,440		(1,632)		(3,025)
Operating Income	428,303		406,042		397,037

Interest expense, net	(143,470)		(137,659)		(139,975)
Impairment of investment	(6,859)		(19,741)		—
Other income (expense), net	(2,293)		(5,740)		(1,180)
Income tax benefit (expense)	(32,918)		(29,580)		23,667
Income from continuing operations	242,763		213,322		279,549
(Loss) from discontinued operations, net of tax	—		—		(6,887)
Net income	242,763		213,322		272,662
Net income attributable to noncontrolling interest	(15,155)		(14,012)		(14,220)
Net income available for common stock	$	227,608	$	199,310	$	258,442

Earnings per share from continuing operations, Diluted	$	3.65	$	3.28	$	4.78
(Loss) per share from discontinued operations, Diluted	—		—		(0.12)
Total earnings per share of common stock, Diluted	$	3.65	$	3.28	$	4.66

_____________

(a) Adjusted operating income recognizes intersegment revenues and costs for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. This presentation of segment information does not impact consolidated financial results.

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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 gross 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’ adjusted operating income decreased $4.2 million due to higher depreciation and amortization expense as a result of additional plant placed in service, lower commercial and industrial demand and COVID-19 impacts partially offset by benefits from the release of TCJA revenue reserves and increased rider revenues;

•Gas Utilities’ adjusted 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 prior year 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;

•Power Generation’s adjusted operating income decreased $2.7 million primarily due to higher depreciation and maintenance expense from new wind assets and expense related to the early retirement of certain assets;

•Corporate and Other expenses decreased $3.1 million primarily due to lower unallocated 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 prior year expensing of $5.4 million of development costs related to projects we no longer intend to construct partially offset by increased current year pension non-service costs; and

•Increased tax expense of $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, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation and amortization from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel and purchased power. Gross margin for our Gas Utilities is calculated as operating revenue less cost of natural gas sold. Our gross margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross 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):


	2020		Variance		2019		Variance		2018

Revenue	$	714,044	$	1,292	$	712,752	$	1,301	$	711,451

Total fuel and purchased power	267,045		(1,252)		268,297		(15,543)		283,840

Gross margin (non-GAAP)	446,999		2,544		444,455		16,844		427,611

Operations and maintenance	196,794		1,213		195,581		9,406		186,175
Depreciation and amortization	94,150		5,573		88,577		3,010		85,567
Total operating expenses	290,944		6,786		284,158		12,416		271,742

Adjusted operating income	$	156,055	$	(4,242)	$	160,297	$	4,428	$	155,869

2020 Compared to 2019

Gross margin increased over the prior year as a result of:


	(in millions)
Release of TCJA revenue reserves (a)	$	2.7
Rider recovery and true-up (b)	2.3
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 Gross margin (non-GAAP)	$	2.5

____________________

(a) 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 Gross margin of $2.7 million. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

(b) Gross margin increased due to $3.5 million of rider revenues, which was partially offset by a $1.2 million rider true-up.

(c) The impacts to Electric Utilities’ gross 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 COVID-19 impacts which included $2.2 million of expenses related to the sequestration of essential employees and $0.8 million of additional bad debt expense which were partially offset by $1.2 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 prior and current year capital expenditures.

Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.

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Operating Statistics


	Electric Revenue (in thousands)						Quantities Sold (MWh)
For the year ended December 31,	2020		2019		2018		2020	2019	2018

Residential	$	221,530	$	216,108	$	218,558	1,477,514	1,440,551	1,450,585
Commercial	239,166		246,704		250,894		1,974,043	2,055,253	2,034,917
Industrial	131,154		131,831		124,668		1,794,795	1,787,412	1,682,074
Municipal	16,860		17,206		17,871		158,222	157,298	160,913
Subtotal Retail Revenue - Electric	608,710		611,849		611,991		5,404,574	5,440,514	5,328,489
Contract Wholesale (a)	17,847		19,078		33,688		492,637	368,360	900,854
Off-system/Power Marketing Wholesale	24,308		25,622		24,800		648,928	701,633	673,994
Other	63,179		56,203		40,972		—	—	—
Total Revenue and Energy Sold	714,044		712,752		711,451		6,546,139	6,510,507	6,903,337
Other Uses, Losses or Generation, net (b)	—		—		—		400,826	393,573	470,250
Total Revenue and Energy	714,044		712,752		711,451		6,946,965	6,904,080	7,373,587
Less cost of fuel and purchased power	267,045		268,297		283,840
Gross Margin (non-GAAP)	$	446,999	$	444,455	$	427,611


	Electric Revenue (in thousands)						Gross Margin (non-GAAP) (in thousands)						Quantities Sold (MWh) (b)
For the year ended December 31,	2020		2019		2018		2020		2019		2018		2020	2019	2018
Colorado Electric	$	253,229	$	247,332	$	251,218	$	139,731	$	137,323	$	138,901	2,379,866	2,180,985	2,151,918
South Dakota Electric (a)	283,153		291,219		298,080		220,456		218,104		205,194		2,563,387	2,798,887	3,360,396
Wyoming Electric	177,662		174,201		162,153		86,812		89,028		83,516		2,003,712	1,924,208	1,861,273
Total Revenue, Gross Margin (non-GAAP), and Quantities Sold	$	714,044	$	712,752	$	711,451	$	446,999	$	444,455	$	427,611	6,946,965	6,904,080	7,373,587

________________

(a) 2020 and 2019 revenue and purchased power, as well as associated quantities, for certain wholesale contracts have been presented on a net basis. 2018 amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.

(b) Includes company uses, line losses, and excess exchange production.


	For the year ended December 31,
Quantities Generated and Purchased by Fuel Type (MWh)	2020	2019	2018
Generated:
Coal	2,273,635	2,226,028	2,368,506
Natural Gas and Oil	581,554	600,002	446,373
Wind	261,400	238,999	253,180
Total Generated	3,116,589	3,065,029	3,068,059
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases (a)	3,235,086	3,576,394	4,134,145
Wind	595,290	262,657	171,383
Total Purchased	3,830,376	3,839,051	4,305,528
Total Generated and Purchased	6,946,965	6,904,080	7,373,587

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	For the year ended December 31,
Quantities Generated and Purchased (MWh)	2020	2019	2018
Generated:
Colorado Electric	364,058	443,770	481,446
South Dakota Electric	1,901,009	1,768,456	1,734,222
Wyoming Electric	851,522	852,803	852,391
Total Generated	3,116,589	3,065,029	3,068,059

Purchased:
Colorado Electric	2,015,808	1,737,215	1,670,472
South Dakota Electric (a)	662,378	1,030,431	1,626,174
Wyoming Electric	1,152,190	1,071,405	1,008,882
Total Purchased	3,830,376	3,839,051	4,305,528

Total Generated and Purchased	6,946,965	6,904,080	7,373,587

____________________

(a) 2020 and 2019 purchased power quantities for a wholesale contract have been presented on a net basis. 2018 amounts were presented on a gross basis and, due to their immaterial nature, were not revised. This presentation change has no impact on Gross margin.


	For the year ended December 31,
Degree Days	2020	2019		2018
	Actual	Variance from Normal	Actual		Variance from Normal	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	5,103	(9)%	5,453		(3)%	5,119	4%
South Dakota Electric	6,910	(3)%	8,284		16%	7,749	8%
Wyoming Electric	6,771	(5)%	7,406		1%	7,036	(7)%
Combined (a)	6,056	(6)%	6,813		5%	6,405	3%

Cooling Degree Days:
Colorado Electric	1,384	54%	1,226		37%	1,420	58%
South Dakota Electric	682	7%	404		(36)%	488	(23)%
Wyoming Electric	594	71%	462		33%	430	24%
Combined (a)	985	41%	791		14%	902	29%

________________

(a) The combined 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)	2020	2019	2018
Coal	94.1%	92.1%	93.9%
Natural gas and diesel oil (b)	80.6%	87.9%	96.4%
Wind	98.1%	95.6%	96.9%
Total availability	87.0%	89.9%	95.6%

Wind capacity factor	38.9%	38.7%	39.2%

____________________

(a) Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.

(b) 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):


	2020		Variance		2019		Variance		2018
Revenue:
Natural gas - regulated	$	900,637	$	(31,474)	$	932,111	$	(10,813)	$	942,924
Other - non-regulated services	74,033		(3,886)		77,919		(4,464)		82,383
Total revenue	974,670		(35,360)		1,010,030		(15,277)		1,025,307

Cost of natural gas sold:
Natural gas - regulated	347,611		(59,032)		406,643		(35,887)		442,530
Other - non-regulated services	7,034		(12,221)		19,255		(368)		19,623
Total cost of sales	354,645		(71,253)		425,898		(36,255)		462,153




Gross margin (non-GAAP)	620,025		35,893		584,132		20,978		563,154

Operations and maintenance	303,577		1,733		301,844		10,363		291,481

Depreciation and amortization	100,559		8,242		92,317		5,883		86,434
Total operating expenses	404,136		9,975		394,161		16,246		377,915

Adjusted operating income	$	215,889	$	25,918	$	189,971	$	4,732	$	185,239

2020 Compared to 2019

Gross margin increased over the prior year 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
Prior year amortization of excess deferred income taxes	2.6
Weather	(1.8)
COVID-19 impacts (a)	(1.8)
Other	2.6
Total increase in Gross margin (non-GAAP)	$	35.9

____________________

(a) The impacts to Gas Utilities’ gross 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 prior and current year capital expenditures. Lower employee costs were mostly offset by various other current year 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 prior and current year capital expenditures.

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Operating Statistics


	Revenue (in thousands)						Gross Margin (non-GAAP) (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,
	2020		2019		2018		2020		2019		2018		2020	2019	2018

Residential	$	527,518	$	551,701	$	567,785	$	298,707	$	285,802	$	276,858	61,962,171	66,956,080	65,352,164
Commercial	193,017		212,229		214,718		89,590		88,264		82,529		28,784,319	32,241,441	30,753,361
Industrial	24,014		24,832		26,466		8,670		8,053		7,056		6,881,354	6,548,023	6,309,211
Other	582		(1,361)		(7,899)		582		(1,361)		(7,899)		—	—	—
Total Distribution	745,131		787,401		801,070		397,549		380,758		358,544		97,627,844	105,745,544	102,414,736

Transportation and Transmission	155,506		144,710		141,854		155,477		144,710		141,850		149,062,476	153,101,264	148,299,003

Total Regulated	900,637		932,111		942,924		553,026		525,468		500,394		246,690,320	258,846,808	250,713,739

Non-regulated Services	74,033		77,919		82,383		66,999		58,664		62,760		—	—	—

Total Revenue, Gross Margin (non-GAAP) and Quantities Sold	$	974,670	$	1,010,030	$	1,025,307	$	620,025	$	584,132	$	563,154	246,690,320	258,846,808	250,713,739


	Revenue (in thousands)						Gross Margin (non-GAAP) (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,
	2020		2019		2018		2020		2019		2018		2020	2019	2018

Arkansas	$	184,849	$	185,201	$	176,660	$	127,720	$	115,899	$	100,917	28,572,621	30,496,243	30,931,390
Colorado	186,085		199,369		188,002		106,749		106,776		99,851		32,077,083	33,908,529	29,857,063
Iowa	137,982		151,619		161,843		69,528		70,290		68,384		36,824,548	41,795,729	40,668,682
Kansas	101,118		105,906		112,306		60,586		58,020		55,226		33,732,897	32,650,854	31,387,672
Nebraska	246,381		255,622		278,969		169,311		155,901		164,513		80,202,783	81,481,192	81,658,938
Wyoming	118,255		112,313		107,527		86,131		77,246		74,263		35,280,388	38,514,261	36,209,994
Total Revenue, Gross Margin (non-GAAP) and Quantities Sold	$	974,670	$	1,010,030	$	1,025,307	$	620,025	$	584,132	$	563,154	246,690,320	258,846,808	250,713,739


	For the year ended December 31,
	2020		2019		2018
Heating Degree Days:	Actual	Variance From Normal		Actual	Variance From Normal	Actual	Variance From Normal
Arkansas (a)	3,442	(15)%		3,897	(4)%	4,169	3%
Colorado	6,068	(8)%		6,672	1%	6,136	(7)%
Iowa	6,504	(4)%		7,200	6%	7,192	6%
Kansas (a)	4,648	(5)%		5,190	6%	5,242	7%
Nebraska	5,853	(5)%		6,578	7%	6,563	6%
Wyoming	7,289	(4)%		8,010	7%	7,425	(1)%
Combined (b)	6,038	(6)%		6,840	5%	6,628	2%

________________

(a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on gross margins.

(b) The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

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Power Generation

Our Power Generation segment operating results for the years ended December 31 were as follows (in thousands):


	2020		Variance		2019		Variance		2018

Revenue	$	105,047	$	3,789	$	101,258	$	8,807	$	92,451

Total fuel	8,993		(66)		9,059		467		8,592
Operations and maintenance	33,695		5,266		28,429		3,294		25,135
Depreciation and amortization	20,247		1,256		18,991		2,881		16,110
Total operating expenses	62,935		6,456		56,479		6,642		49,837

Adjusted operating income	$	42,112	$	(2,667)	$	44,779	$	2,165	$	42,614

2020 Compared to 2019

Revenue increased in the current year due to increased wind megawatt hours sold primarily driven by Busch Ranch II, additional Black Hills Colorado IPP fired-engine hours and higher power sales agreement prices and volumes. Operating expenses increased in the current year primarily due to a $3.1 million expense related to the early retirement of certain assets and higher depreciation and maintenance expense from new wind assets. COVID-19 impacts included $0.4 million of expenses related to the sequestration of essential employees which were mostly offset by lower travel and training expenses.

Operating Statistics



	Revenue (in thousands)						Quantities Sold (MWh) (a)
For the year ended December 31,	2020		2019		2018		2020	2019	2018
Black Hills Colorado IPP	$	57,057	$	55,191	$	55,331	1,076,819	935,997	1,000,577
Black Hills Wyoming	42,464		41,822		36,978		633,389	629,788	582,938
Black Hills Electric Generation	5,526		4,245		142		353,559	167,296	5,873
Total Revenue and Quantities Sold	$	105,047	$	101,258	$	92,451	2,063,767	1,733,081	1,589,388

____________________

(a) Company use and losses are not included in the quantities sold.



		For the year ended December 31,
Quantities Generated and Purchased (MWh) (a)	Fuel Type	2020	2019	2018
Generated:
Black Hills Colorado IPP	Natural Gas	1,076,819	935,997	1,000,577
Black Hills Wyoming	Coal	551,136	557,119	501,945
Black Hills Electric Generation	Wind	353,559	167,296	5,873
Total Generated		1,981,514	1,660,412	1,508,395
Purchased:
Black Hills Wyoming (b)	Various	82,525	74,199	83,213
Total Generated and Purchased		82,525	74,199	83,213

____________________

(a) Company use and losses are not included in the quantities generated and purchased.

(b) Under the 20-year economy energy PSA (discussed in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K) with the City of Gillette, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette. MWh sold may not equal MWh generated and purchased due to a dispatch agreement Black Hills Wyoming has with South Dakota Electric to cover energy imbalances.

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	For the year ended December 31,
Contracted generating facilities availability by fuel type (a)	2020	2019	2018
Coal	95.4%	94.5%	85.8%
Natural gas	99.5%	98.6%	99.4%
Wind	92.8%	90.6%	N/A
Total availability	96.4%	95.0%	95.9%

Wind capacity factor	26.6%	23.5%	N/A

___________

(a) Availability and wind capacity factor are calculated using a weighted average based on capacity of our generating fleet.

Mining

Mining operating results for the years ended December 31 were as follows (in thousands):


	2020		Variance		2019		Variance		2018

Revenue	$	61,075	$	(554)	$	61,629	$	(6,404)	$	68,033

Operations and maintenance	39,033		(999)		40,032		(3,696)		43,728
Depreciation, depletion and amortization	9,235		265		8,970		1,005		7,965
Total operating expenses	48,268		(734)		49,002		(2,691)		51,693

Adjusted operating income	$	12,807	$	180	$	12,627	$	(3,713)	$	16,340

2020 Compared to 2019

Adjusted operating income was comparable to the prior year.

Operating Statistics


For the year ended December 31,	2020		2019		2018
Tons of coal sold	3,737		3,716		4,085

Cubic yards of overburden moved	8,120		8,534		8,970

Coal reserves at year-end (in tons)	181,711		185,448		189,164

Revenue per ton	$	15.67	$	15.94	$	16.11

Corporate and Other

Corporate and Other operating results for the years ended December 31 were as follows (in thousands):


(in thousands)	2020		Variance		2019		Variance		2018

Adjusted operating income (loss)	$	1,440	$	3,072	$	(1,632)	$	1,393	$	(3,025)

(in thousands) 2019 Variance 2018 Variance 2017

Adjusted operating (loss) ^(a)
$ (1,632 ) $ 1,393
$ (3,025 ) $ 3,271
$ (6,296 )

~~____________~~


~~(a)~~	~~Due to the changes in our segment disclosures discussed in~~ ~~Note 5~~ of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, Corporate and Other Adjusted operating (loss) was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in a decrease of $(0.7) million and $(0.6) million, respectively.

~~2019~~2020 Compared to ~~2018~~2019

The variance in Adjusted operating income (loss) was primarily due to ~~prior year expenses related to the oil and gas segment that were not reclassified to discontinued operations.~~

~~2018 Compared to 2017~~

~~The variance in Adjusted operating (loss) was primarily due to prior year acquisition~~lower unallocated employee costs.

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Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)


(in thousands)	2020		Variance		2019		Variance		2018

Interest expense, net	$	(143,470)	$	(5,811)	$	(137,659)	$	2,316	$	(139,975)
Impairment of investment	(6,859)		12,882		(19,741)		(19,741)		—
Other income (expense), net	(2,293)		3,447		(5,740)		(4,560)		(1,180)
Income tax benefit (expense)	(32,918)		(3,338)		(29,580)		(53,247)		23,667

(in thousands) 2019 Variance 2018 Variance 2017

Interest expense, net $ (137,659 ) $ 2,316
$ (139,975 ) $ (2,873 ) $ (137,102 )
Impairment of investment (19,741 ) (19,741 ) —
—
—
Other income (expense), net (5,740 ) (4,560 ) (1,180 ) (3,288 ) 2,108
Income tax benefit (expense) (29,580 ) (53,247 ) 23,667
97,034
(73,367 )

~~2019~~2020 Compared to ~~2018~~2019

Interest Expense

The increase in Interest expense, net was driven by higher debt balances partially offset by lower interest rates.

Impairment of Investment

~~For~~In the current year, ~~ended December 31, 2019,~~ we recorded a pre-tax non-cash write-down of ~~$20~~$6.9 million in our investment in equity

securities of a privately held oil and gas ~~company.~~company, compared to a $20 million write-down in the prior year. The ~~impairment was~~impairments in both years were triggered by ~~a deterioration in earnings performance of~~

continued adverse natural gas prices and liquidity concerns at the privately held oil and gas ~~company~~company. The remaining book value of our investment is $1.5 million, and ~~an adverse change~~this is our only remaining investment in ~~future natural~~oil and gas ~~prices.~~exploration and production activities. See Note 1 of the Notes to

Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

Other Income (Expense)

~~For~~The variance in Other income (expense), net was due to the prior year ~~ended December 31, 2019, we expensed~~expensing of $5.4 million of development costs related to projects we no longer intend to ~~construct.~~construct which was partially offset by higher current year non-service defined benefit plan costs primarily driven by lower discount rates.

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 ~~increase in~~lower effective tax ~~expense was~~rate is primarily due to ~~a prior year $73 million~~increased tax ~~benefit resulting~~benefits from ~~legal entity restructuring partially offset by:~~

~~A prior year $(4.0) million income~~federal production tax ~~expense associated with changes in the previously estimated impact of tax reform on deferred income taxes;~~

~~Current year $3.8 million of federal PTCs and $2.1 million of related state ITCs~~credits associated with new wind ~~assets;~~

~~A current~~assets and one-time research and development tax credits partially offset by a prior year ~~$1.9 million tax benefit from increased repair activity in flow-through regulatory jurisdictions;~~

~~A current year $1.4 million tax benefit for incremental excess deferred tax amortization related to tax reform; and~~

~~A current year $3.4 million~~ tax benefit from a federal tax loss carry-back claim including interest. ~~We identified certain qualified expenses that extend beyond~~See Note 17 of the ~~typical two-year carry-back period.~~Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

~~2018 Compared to 2017~~

~~Other Income (Expense)~~

The variance in Other income (expense), net was primarily due to the presentation change of non-service pension costs to Other income (expense) in 2018, previously reported in Operations and maintenance.

~~Income Tax Benefit (Expense)~~

The variance in Income tax benefit (expense) was primarily due to a $73 million tax benefit in 2018 resulting from legal entity restructuring and the reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018, partially offset by a $(4.0) million income tax expense associated with changes in the previously estimated impact of tax reform on deferred income taxes.

Liquidity and Capital Resources

OVERVIEW

Our company requires significant cash to support and grow our businesses. Our ~~predominant source~~primary sources of cash isare generated from our ~~operations~~operating activities, five-year Revolving Credit Facility, CP Program, ATM and ~~supplemented with corporate financings.~~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 and during periods of high natural gas prices, as well as during the construction ~~season.~~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 the February 2021 weather event and the COVID-19 pandemic, we took steps to maintain adequate liquidity to operate our businesses and fund our capital investment program as discussed in the Company Highlights above.

Table of Contents

The following table provides an informational summary of our financial position as of December 31 (dollars in thousands):


Financial Position Summary	2019			2018			Financial Position Summary	2020			2019
Cash and cash equivalents	$	9,777		$	20,776		Cash and cash equivalents	$	6,356		$	9,777
Restricted cash and equivalents	$	3,881		$	3,369		Restricted cash and equivalents	$	4,383		$	3,881
Notes payable	$	349,500		$	185,620		Notes payable	$	234,040		$	349,500
Short-term debt, including current maturities of long-term debt	$	5,743		$	5,743
Current maturities of long-term debt							Current maturities of long-term debt	$	8,436		$	5,743
Long-term debt ^(a)	$	3,140,096		$	2,950,835		Long-term debt (a)	$	3,528,100		$	3,140,096
Stockholders’ equity	$	2,362,123		$	2,181,588		Stockholders’ equity	$	2,561,385		$	2,362,123

Ratios							Ratios
Long-term debt ratio	57		%	57		%	Long-term debt ratio	58		%	57		%
Total debt ratio	60		%	59		%	Total debt ratio	60		%	60		%

______________


~~(a)~~	(a) Carrying amount of long-term debt is net of deferred financing costs.

~~Significant Factors Affecting Liquidity~~

~~Although we believe we have sufficient resources to fund~~

CASH FLOW ACTIVITIES

The following table summarizes our cash requirements, there are many factors with the potential to influence our cash flow position, including weather seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow. However, the potential for unforeseen events affecting cash needs will continue to exist.

~~Our Utilities maintain wholesale commodity contracts~~flows for the ~~purchases and sales of electricity and natural gas which have performance assurance provisions that allow~~years ended December 31 (in thousands):


	2020		2019		2018
Cash provided by (used in)
Operating activities	$	541,863	$	505,513	$	488,811
Investing activities	$	(761,664)	$	(816,210)	$	(465,849)
Financing activities	$	216,882	$	300,210	$	(17,057)

2020 Compared to 2019

Operating Activities:

Net cash provided by operating activities was $36 million higher than in 2019. The variance to the ~~counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in~~prior year was primarily attributable to:

•Cash earnings (income from continuing operations plus non-cash adjustments) were $20 million higher than prior year driven primarily by higher operating income at 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,Gas Utilities;

•Net inflows from changes in ~~the market price, open positions~~certain operating assets and ~~the amounts owed~~liabilities were $18 million higher than prior year, primarily attributable to:

•Cash inflows decreased by ~~or to the counterparty. At December 31, 2019, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts.~~

~~Weather Seasonality, Commodity Pricing and Associated Hedging Strategies~~

~~We manage liquidity needs through hedging activities,~~approximately $18 million primarily ~~in connection with seasonal needs of our utility operations (including seasonal peaks in fuel requirements), interest rate movements and commodity price movements.~~

~~Utility Factors~~

Our cash flows, and in turn liquidity needs in many of our regulated jurisdictions, can be subject to fluctuations in weather and commodity prices. Since weather conditions are uncontrollable, we have implemented commission-approved natural gas hedging and storage programs in many of our regulated jurisdictions to mitigate significant changes in natural gas commodity pricing. We target hedging a percentage of our forecasted natural gas supply consumption using options, futures, basis swaps and physical fixed price purchases.

~~Interest Rates~~

~~Some of our debt instruments have a variable interest rate component which can change significantly depending on the economic climate. We do not have any interest rate swap agreements at~~ ~~December 31, 2019; 90% of our interest rate exposure has been mitigated through fixed interest rates.~~

~~Federal and State Regulations~~

We are structured as a utility holding company which owns several regulated utilities. Within this structure, we are subject to various regulations by our commissions that can influence our liquidity. As an example, the issuance of debt by our regulated subsidiaries and the use of our utility assets as collateral generally require prior approval of the state regulators in the state in which the utility assets are located. Furthermore, as a result of ~~our holding company structure, our right~~changes in accounts receivable and other current assets driven by warmer weather, lower commodity prices and COVID-19 related impacts;

•Cash outflows decreased by approximately $60 million as a ~~common shareholder~~result of changes in accounts payable and other current liabilities driven by the impact of lower commodity prices, deferral of payroll taxes under the CARES Act and other working capital requirements; and

•Cash outflows increased by approximately $24 million primarily as a result of changes in our regulatory assets and liabilities driven by timing of recovery and returns for fuel costs adjustments partially offset by the TCJA tax rate change that was returned to ~~receive assets~~customers in the prior year.

•Cash inflows decreased $1.3 million for other operating activities.

Table of ~~any of our direct or indirect subsidiaries upon a subsidiary's liquidation or reorganization is subordinate~~Contents

Investing Activities:

Net cash used in investing activities was $55 million lower than in 2019. This variance to the ~~claims against~~prior year was primarily attributable to:

•Capital expenditures of approximately $767 million in 2020 compared to $818 million in 2019. Higher prior year expenditures were driven by large projects such as the ~~assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing~~Natural Bridge pipeline project, the Busch Ranch II wind project and ~~future claims~~construction of the ~~creditors~~final segment of ~~our subsidiaries, including trade creditors,~~the 175-mile transmission line from Rapid City, South Dakota to Stegall, Nebraska. The current year capital expenditures included the Corriedale wind project.

•Cash inflows increased $3.6 million for other investing activities.

Financing Activities:

Net cash provided by financing activities was $83 million lower than in 2019. This variance to the prior year was primarily attributable to:

•Cash inflows decreased $82 million due to maturities and repayments of long and short-term debt ~~holders, secured creditors, taxing authorities~~in excess of issuances;

•Cash outflows increased $11 million due to increased dividends paid on common stock; and ~~guarantee holders.~~

~~CASH GENERATION AND CASH REQUIREMENTS~~•Cash outflows decreased by $9.7 million for other financing activities primarily driven by lower current year financing costs incurred in the June 17, 2020 debt transaction compared to prior year financing costs incurred in the June 17, 2019 and October 3, 2019 debt transactions.

~~Cash Generation~~

Our primary sources of cash are generated from operating activities, our five-year Revolving Credit Facility expiring in 2023, our CP Program, our ATM equity offering program and our ability to access the public and private capital markets through debt and equity securities offerings when necessary.CAPITAL SOURCES

~~Cash Collateral~~

Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral with the counterparty to meet these obligations. The cash collateral we were required to post at December 31, 2019 was not material.

~~DEBT, EQUITY AND LIQUIDITY~~

~~Debt~~

Revolving Credit Facility and CP Program

~~On July 30, 2018, we amended and restated our corporate~~We have a $750 million Revolving Credit Facility ~~maintaining total commitments of $750 million and extending the term through~~that matures on July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility ~~is similar to the former revolving credit facility, which~~ includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments up to $1.0 billion. ~~Borrowings continue to be available under a base rate or various Eurodollar rate options. See~~ ~~Note 7~~ ~~of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.~~

We 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. ~~See~~ ~~Note 7~~ ~~of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.~~

~~Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):~~

Current Short-term borrowings at Letters of Credit at Available Capacity at
Credit Facility Expiration Capacity December 31, 2019 December 31, 2019 December 31, 2019
Revolving Credit Facility and CP Program July 30, 2023 $ 750
$ 350
$ 30
$ 370

~~The weighted average interest rate on short-term borrowings at December 31, 2019 was 2.03%. Short-term borrowing activity for the twelve months ended December 31, 2019 was:~~

(dollars in millions)
Maximum amount outstanding - short-term borrowing (based on daily outstanding balances) $ 357
Average amount outstanding - short-term borrowing (based on daily outstanding balances) $ 187
Weighted average interest rates - short-term borrowing 2.47 %

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on certain liens, restrictions on certain transactions, and maintenance of a certain Consolidated Indebtedness to Capitalization Ratio. We were in compliance with these covenants as of December 31, 2019. See
~~Note 7~~ ~~of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.~~

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

~~Cross-Default Provisions~~

~~Our $7 million Corporate term loan~~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~~obligations; or 2) triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that ~~permits~~permit the acceleration of debt maturities or mandatory debt prepayment.

Our Revolving Credit Facility ~~contains~~and CP Program had the ~~same provisions~~following borrowings, outstanding letters of credit, and available capacity (in millions):


		Current		Short-term borrowings at		Letters of Credit (a) at		Available Capacity at
Credit Facility	Expiration	Capacity		December 31, 2020		December 31, 2020		December 31, 2020
Revolving Credit Facility and CP Program	July 30, 2023	$	750	$	234	$	25	$	491

__________

(a) Letters of credit are off-balance sheet commitments that reduce the ~~threshold principal amount is $50 million.~~borrowing capacity available on our corporate Revolving Credit. For more information on these letters of credit, see Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Table of Contents

The weighted average interest rate on short-term borrowings at December 31, 2020 was 0.27%. Short-term borrowing activity for the year ended December 31, 2020 was:


	(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)	$	366

Average amount outstanding (based on daily outstanding balances)	$	193

Weighted average interest rate	0.90		%

See Note 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our Revolving Credit Facility ~~prohibits us from paying cash dividends if we are in default or if paying dividends would cause us to be in default.~~and CP Program.

Utility Money Pool

As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may, at their option, borrow and extend short-term loans to our other utilities via a utility money pool at market-based ~~rates (2.210% at~~ ~~December 31, 2019~~).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 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.


	Payments Due by Period
	2021		2022		2023		2024		2025		Thereafter		Total
Principal payments on Long-term debt including current maturities (a)	$	8,436	$	—	$	525,000	$	—	$	—	$	3,035,000	$	3,568,436
Interest payments on Long-term debt (a)	141,561		141,547		141,547		119,235		119,235		1,209,188		1,872,313

__________

(a)Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, ~~2019, money pool balances included (in thousands):~~2020.

Subsidiary
Borrowings From
Money Pool Outstanding
BHSC $ 148,041
South Dakota Electric 57,585
Wyoming Electric 37,993
Total Money Pool borrowings from Parent $ 243,619
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, 2020. See additional information in Note 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K

Equity

Shelf Registration

We have ~~an effective automatic~~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 ~~2020.~~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, ~~2019,~~2020, we had approximately 6163 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. In ~~2019,~~2020, we ~~issued a total of 1,328,332~~did not issue any shares of common stock under the ~~ATM for proceeds of $99 million, net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled.~~

~~Common Stock Dividends~~

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.

On January 29, 2020, our Board of Directors declared a quarterly dividend of $0.535 per share, equivalent to an annual dividend rate of $2.14 per share. The table below provides our historical three-year dividend payout ratio and dividends paid per share:

2019 2018 2017
Dividend Payout Ratio 63% 40% 50%
Dividends Per Share $2.05 $1.93 $1.81

~~Our three-year compound annualized dividend growth rate was 6.9% and all dividends were paid out of available operating cash flows.~~

~~Dividend Restrictions~~

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. Our utilities in Arkansas, Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and neither BHSC nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. The use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.

ATM.

As a result of our holding company structure, our right as a common shareholder to receive assets from any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders. See

For additional information inregarding equity, see Note 610 of our Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K.

Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not comply with certain financial or other covenants. See additional information in ~~Note 7~~ ~~of our Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~

~~Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio~~Table of ~~no more than 0.60 to 1.00. As of~~ ~~December 31, 2019, we were in compliance with these covenants.~~Contents

~~Financing Activities~~

~~Financing activities in 2019 consisted of the following:~~

~~We issued a total of 1.3 million shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.2 million in issuance costs.~~

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029, and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, and repay a portion of short-term debt.

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continued to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

~~Short-term borrowings from our Revolving Credit Facility and CP Program.~~

Future Financing Plans

We ~~anticipate the following financing activities in 2020:~~

~~Renew our shelf registration and ATM;~~

~~Continued equity issuance under the ATM or assess other equity issuance options;~~

~~Refinance a portion of short-term borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and~~

~~Continue~~will continue to assess debt and equity needs to support our capital ~~expenditure plan.~~

~~CASH FLOW ACTIVITIES~~

~~The following table summarizes our cash flows (in thousands):~~

2019 2018 2017
Cash provided by (used in)
Operating activities $ 505,513
$ 488,811
$ 428,261
Investing activities $ (816,210 ) $ (465,849 ) $ (317,118 )
Financing activities $ 300,210
$ (17,057 ) $ (108,695 )

~~2019 Compared to 2018~~

~~Operating Activities:~~

~~Net cash provided by operating activities was $17 million higher than in 2018. The variance to the prior year was primarily attributable to:~~

~~Cash earnings (income from continuing operations plus non-cash adjustments) were $37 million higher than prior year driven primarily by higher margins at our Electric and Gas Utilities;~~

~~Net outflows from operating assets and liabilities were $25 million higher than prior year, primarily attributable to:~~

~~Cash outflows increased by approximately $40 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of higher outside services, employee costs~~investment plans and other ~~working capital requirements;~~

Cash inflows increased by approximately $59 million compared to the prior year primarily as a result of lower accounts receivable driven by lower pass-through revenues reflecting lower commodity prices; and

Cash inflows decreased by approximately $44 million primarily as a result of changes in our current regulatory liabilities due to the TCJA tax rate change that has subsequently been returned to customers and from changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity prices; and

~~Cash outflows decreased approximately $5.5 million due to the absence of operating activities of discontinued operations in 2019.~~

~~Investing Activities:~~

Net cash used in investing activities was $816 million in 2019, compared to net cash used in investing activities of $466 million in 2018 for a variance of $350 million. This variance was primarily due to:

Capital expenditures of approximately $818 million in 2019 compared to $458 million in 2018. The $361 million increase from the prior year was due to higher capital expenditures driven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities segments, the Corriedale Wind Energy Project at our Electric Utilities segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska, at our Electric Utilities segment, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, and construction of Busch Ranch II at our Power Generation segment; and

~~Net cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of our oil and gas segment.~~

~~Financing Activities:~~

~~Net cash provided by financing activities was $300 million in 2019 as compared to net cash used by financing activities of $17 million in 2018, an increase of $317 million due to the following:~~

~~Increase of $539 million due to issuances of long and short-term debt in excess of required maturities that were used~~key strategic objectives. In 2021, we expect to fund our capital ~~program~~

~~Decrease~~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 ~~$199 million in~~ common stock ~~issued primarily due to prior year gross proceeds of approximately $299 million from~~under the ~~Equity Unit conversion partially offset by current year net proceeds of $99 million through our ATM equity offering program;~~

~~Cash dividends on common stock of $125 million were paid in 2019 compared to $107 million paid in 2018; and~~

~~Cash outflows for other financing activities increased by approximately $5.5 million driven primarily by current year financing costs incurred~~ATM. As discussed in the ~~October 3, 2019 debt transaction.~~

~~CAPITAL EXPENDITURES~~

~~Capital expenditures are~~Company Highlights above, on February 24, 2021, we entered into an $800 million term loan maturing on November 23, 2021. We expect to repay a ~~substantial~~ portion of ~~our cash requirements each year~~this term loan prior to maturity and ~~we continue to forecast a robust capital expenditure program during~~refinance the ~~next five years. See Key Elements of our Business Strategy above~~remaining portion in ~~Item 7 - Executive Summary and Business Strategy~~ ~~for forecasted capital expenditure requirements.~~longer-term debt.

A significant portion of our capital expenditures relates to safety, reliability and integrity assets benefiting customers that may be included in utility rate base and can be recovered from our utility customers following regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.

~~Historical Capital Requirements~~

~~Our primary capital requirements for the three years ended December 31 were as follows (in thousands):~~

2019 2018 2017
Property additions: ^(a)

Electric Utilities ^(b)
$ 222,911
$ 152,524
$ 138,060
Gas Utilities ^(c)
512,366
288,438
184,389
Power Generation ^(d)
85,346
30,945
1,864
Mining 8,430
18,794
6,708
Corporate and Other 20,702
11,723
6,668
Capital expenditures before discontinued operations 849,755
502,424
337,689
Discontinued operations —
2,402
23,222
Total capital expenditures 849,755
504,826
360,911
Common stock dividends 124,647
106,591
96,744
Maturities/redemptions of long-term debt 905,743
854,743
105,743
Total capital requirements $ 1,880,145
$ 1,466,160
$ 563,398

~~____________________________~~


~~(a)~~	~~Includes accruals for property, plant and equipment as disclosed in~~ ~~Note 17~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~


~~(b)~~	Current year capital expenditures at our Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Corriedale wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska.


~~(c)~~	~~Current year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the 35-mile Natural Bridge pipeline project.~~


~~(d)~~	~~Current year capital expenditures at our Power Generation segment increased due to construction of Busch Ranch II.~~

CREDIT RATINGS ~~AND COUNTERPARTIES~~

Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. ~~BHC notes~~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, ~~2019~~:

2020:



Rating Agency	Senior Unsecured Rating	Outlook
S&P ^(a)	BBB+	Stable
Moody’s ^(b)	Baa2	Stable
Fitch ^(c)	BBB+	Stable

__________


~~(a)~~	~~On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.~~


~~(b)~~	~~On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.~~


~~(c)~~	~~On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.~~

(a) On April 10, 2020, S&P reported BBB+ rating and maintained a Stable outlook.

(b) On December 21, 2020, Moody’s reported Baa2 rating and maintained a Stable outlook.

Certain ~~of our~~ fees and ~~our~~ interest rates under ~~various bank credit agreements~~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 ~~downgraded~~downgrades our senior unsecured debt, we will be required to pay higher fees and interest rates under ~~these bank credit agreements.~~

our Revolving Credit Facility.

The following table represents the credit ratings of South Dakota Electric at December 31, ~~2019~~:

2020:



Rating Agency			Senior Secured Rating
S&P ^(a)			A
Moody’s ^(b)			A1
Fitch ^(c)			A

__________


~~(a)~~	~~On April 30, 2019, S&P affirmed A rating.~~


~~(b)~~	~~On December 20, 2019, Moody’s affirmed A1 rating.~~


~~(c)~~	~~On August 29, 2019, Fitch affirmed A rating.~~

(a) On April 16, 2020, S&P reported A rating.

(b) On December 21, 2020, Moody’s reported A1 rating.

We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.

~~CONTRACTUAL OBLIGATIONS AND OTHER COMMITMENTS~~

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~~Contractual~~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 o ur Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity benefiting customers that may be included in utility rate base and eligible to be recovered 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.

As discussed in the Company Highlights above, there have been limited impacts from COVID-19 on our capital investment plan and we do not anticipate a significant impact in 2021.

Our capital expenditures for the three years ended December 31 were as follows (in thousands):


	2020		2019		2018
Capital Expenditures By Segment (a) :
Electric Utilities	$	271,104	$	222,911	$	152,524
Gas Utilities	449,209		512,366		288,438
Power Generation	9,329		85,346		30,945
Mining	8,250		8,430		18,794
Corporate and Other	17,500		20,702		11,723
Capital expenditures before discontinued operations	755,392		849,755		502,424
Discontinued operations	—		—		2,402
Total capital expenditures	$	755,392	$	849,755	$	504,826

____________________________

Unconditional Purchase Obligations

~~In addition to~~We have unconditional purchase obligations which include the energy and capacity costs associated with our ~~capital expenditure programs, we have contractual obligations~~PPAs, transmission services agreements, and ~~other commitments that will need to be funded in the future. The following information summarizes~~natural gas capacity, transportation and storage agreements. Additionally, our ~~cash obligations and commercial commitments at~~ ~~December 31, 2019. Actual future obligations may differ materially from these estimated amounts (in thousands):~~

Payments Due by Period
Contractual Obligations 2020 2021 2022 2023 2024 Thereafter Total
Long-term debt^(a)
$ 5,743
$ 8,435
$ —
$ 525,000
$ 2,855
$ 2,635,000
$ 3,177,033
Interest payments ^(a)
131,859
131,842
131,756
131,756
109,390
1,273,648
1,910,251
Unconditional purchase obligations^(b)
181,773
159,827
134,018
105,583
54,098
126,147
761,446
Lease obligations^(c)
1,144
991
869
844
724
2,009
6,581
AROs ^(d)
330
231
144
33
9,362
54,105
64,205
Employee benefit plans^(e)
18,921
19,678
19,736
19,944
19,896
35,580
133,755
CP Program 349,500
—
—
—
—
—
349,500
Total contractual cash obligations^(f)
$ 689,270
$ 321,004
$ 286,523
$ 783,160
$ 196,325
$ 4,126,489
$ 6,402,771

~~__________~~


~~(a)~~	Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of ~~December 31, 2019~~.

~~(b)~~

Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas transportation and storage agreements. The energy charges under the PPAs are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2019 and price assumptions using existing prices at ~~December 31, 2019. Our transmission obligations are based on filed tariffs as of~~ ~~December 31, 2019~~.


~~(c)~~	~~Includes leases associated with several office and operating facilities, communication tower sites, equipment and materials storage.~~


~~(d)~~	~~Represents estimated payments for AROs associated with long-lived assets primarily related to retirement and reclamation of natural gas pipelines, mining sites, wind farms and an evaporation pond. See~~ ~~Notes 1~~ ~~and~~ 8 ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.~~


~~(e)~~	Represents estimated employer contributions to the Defined Benefit Pension Plan, the Non-Pension Defined Benefit Postretirement Healthcare Plan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2029 as discussed in ~~Note 18~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~

~~(f)~~

~~Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including commodity related contracts that have a negative fair value at~~ ~~December 31, 2019~~. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table; (3) our $4.2 million liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions as discussed in ~~Note 15~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~

~~Our~~ Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. ~~In addition, a portion~~For additional information. see Note 3 of our ~~gas purchases are purchased under evergreen contracts and therefore, for purposes~~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 ~~this disclosure, are carried out for 60 days. As~~the Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the plan is $40 million as of December 31, ~~2019,~~2020 compared to $51 million as of December 31, 2019. We do not have required 2021 contributions and currently do not expect to contribute to our Pension Plan. See further information in Note 15 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-Ks.

Common Stock Dividends

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 9 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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On January 27, 2021, our Board of Directors declared a quarterly dividend of $0.565 per share, equivalent to an annual dividend rate of $2.26 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:


	2020			2019		2018
Common Stock Dividends Paid	$	135,439		$	124,647	$	106,591
Dividend Payout Ratio	60		%	63%		40%
Dividends Per Share	$	2.17		$	2.05	$	1.93

Our three-year compound annualized dividend growth rate was 6.2% and all dividends were paid out of available operating cash flows.

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 ~~are committed~~may be required to ~~purchase 3.7 million MMBtu, 3.7 million MMBtu, and 1.8 million MMBtu~~provide at any point in ~~each~~the future is dependent on the amount of the ~~years from 2020 to 2022, respectively.~~

~~Off-Balance Sheet Commitments~~

~~We have entered into various off-balance sheet commitments~~initial transaction, changes in the ~~form~~market price, open positions and the amounts owed by or to the counterparty. At December 31, 2020, 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, 2020 was not material. For the year ended December 31, 2020, we did not experience any requests to post additional collateral, including for concerns over a potential deterioration of ~~guarantees and letters of credit.~~our financial condition due to COVID-19.

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 203 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K.

~~Letters of Credit~~

~~Letters of credit reduce the borrowing capacity available on our corporate Revolving Credit Facility. For more information on these letters of credit, see~~ ~~Note 7~~ ~~of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.~~

Critical Accounting Policies Involving Significant ~~Accounting~~ Estimates

We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. We continue to closely monitor the rapidly evolving and uncertain impact of COVID-19 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~~“Business Description and Significant Accounting ~~Policies~~”Policies” of our Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K.

Regulation

Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.

Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

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To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state ~~public utility~~regulatory commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs. ~~Any such costs not recovered through rates, or any such refund, could adversely affect our results of operations, financial position or cash flows.~~

As of December 31, ~~2019~~2020 and ~~2018,~~2019, we had total regulatory assets of ~~$271~~$278 million and ~~$284~~$271 million, respectively, and total regulatory liabilities of ~~$537~~$533 million and ~~$541~~$537 million, respectively. See Note 132 of the Notes to ~~the~~ Consolidated Financial Statements for further information.

Goodwill

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns ~~our testing date~~ with our financial planning process.

Accounting standards for testing goodwill for impairment require the application of either a ~~two-step process be performed~~qualitative or quantitative assessment to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. ~~The first step of this test, used to identify potential impairment, compares~~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, ~~under the first step,~~ then ~~the second step of the~~an impairment ~~test is performed~~loss would be recognized in an amount equal to ~~measure~~that excess, limited to the amount of ~~any impairment loss.~~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 ~~segment management~~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 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed ~~in the fourth quarter~~as of ~~2019.~~October 1, 2020. Although 1% to 2% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate ~~reviews, as well as other improved efficiency and cost reduction initiatives.~~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, 2020, 2019, ~~2018,~~ and ~~2017,~~2018, there were no impairment losses recorded. At December 31, ~~2019,~~2020, the fair value substantially exceeded the carrying value at all reporting units.

As described in Note 1 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K, we ~~have prospectively~~ adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, prospectively on January 1, 2020.

Pension and Other Postretirement Benefits

As described in Note 1815 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A 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.

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Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company uses a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement.

The ~~2020~~2021 pension benefit cost for our non-contributory funded pension plan is expected to be ~~$10.2~~$0.5 million compared to ~~$2.1~~$4 million in ~~2019.~~2020. The ~~increase~~decrease in the expected 2021 pension benefit cost is driven primarily by favorable asset returns partially offset by a decrease in the discount ~~rate and lower expected return on assets.~~rate.

The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:

December 31,

Assumptions

Percentage Change

2020

Increase/(Decrease)

PBO/APBO (a)

2021
Increase/(Decrease) Expense - Pretax

Pension

~~December 31,~~

~~Assumptions~~

~~Percentage Change~~

~~2019~~

~~Increase/(Decrease)~~

~~PBO/APBO~~ ^(a)

~~2020~~

~~Increase/(Decrease) Expense - Pretax~~

~~Pension~~

Discount rate ^(b)

+/- 0.5

~~(28,998)~~(30,334)/~~31,912~~33,326

~~(3,965)~~(3,162)/~~4,311~~3,743

Expected return on assets

+/- 0.5

N/A

~~(2,036)~~(2,367)/~~2,036~~2,372

OPEB

Discount rate ^(b)

+/- 0.5

~~(2,836)~~(3,139)/~~3,095~~3,425

~~90/116~~(100)/108

Expected return on assets

+/- 0.5

N/A

~~(39)~~(38)/3938

__________________________


~~(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.~~

(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.

As of December 31, ~~2019,~~2020, we have a regulatory liability associated with TCJA related items of $285 million, completing our accounting for the revaluation of deferred taxes pursuant to the TCJA. A significant portion of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets.

As of December 31, ~~2019,~~2020, the Company has amortized ~~$6.5~~$13.3 million of regulatory liability associated with TCJA related items. The portion that was eligible for amortization under the average rate assumption method in ~~2019,~~2020, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.

See Note 1517 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

~~Market Risk Disclosures~~

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~~Our market risk disclosures are detailed in~~

New Accounting Pronouncements

See Note 91 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K ~~with additional~~for information ~~provided~~on new accounting standards adopted in 2020 or pending adoption.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our activities in the ~~following paragraphs.~~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.

~~Our exposure~~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 detailed in~~ risks:

~~Note 9~~•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 the ~~Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K is also affected by~~COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric 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 ~~size, duration and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates~~2008 financial crisis and the ~~liquidity~~COVID-19 pandemic.

Credit risk is associated with financial loss resulting from non-performance of ~~the related interest rate and commodity markets.~~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, ~~appropriate or desirable,~~ 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

~~We produce, purchase and distribute power in four states, and purchase and distribute natural gas in six states.~~ 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 ~~“true-up”~~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 ~~commissions.~~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 911 of the Notes to ~~the~~ 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 qualifying 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 ~~wholesale~~ power that exceeds our generating capacity. These potential short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.

~~Financing Activities~~

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.

See additional commodity risk and derivative information in Note 11 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, ~~2019~~,2020, we had no interest rate swaps in place. ~~As discussed in~~ ~~Item 7 - Liquidity and Capital Resources, 90% of our variable interest rate exposure has been mitigated through issuing fixed rate debt.~~

Further details of past swap agreements are set forth in Note 911 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form 10-K.

~~Credit Risk~~

~~Our credit~~At December 31, 2020, 93% 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 $2.1 million and $4.6 million for the years ended December 31, 2020 and 2019, respectively. See Note 9 for further information on cash amounts outstanding under short- and long-term variable rate borrowings.

We are subject to interest rate risk ~~disclosures are detailed~~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 91 5 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form ~~10-K, with additional information provided below.~~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. ~~In addition, our Executive Risk Committee, which includes senior executives, meets on a regular basis~~We attempt to ~~review~~mitigate our credit ~~activities~~exposure by conducting business primarily with high credit quality entities, setting tenor and ~~to monitor compliance~~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 ~~adopted policies.~~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, 2020 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.

~~New Accounting Pronouncements~~

See more information in Notes 1~~Note 1~~ and 11 of the Notes to ~~the~~ Consolidated Financial Statements in this Annual Report on Form ~~10-K for information on new accounting standards adopted in 2019 or pending adoption.~~10-K.


~~ITEM 8.~~	~~FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA~~

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~~INDEX TO CONSOLIDATED~~ ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



~~Management’s Report on Internal Controls Over Financial Reporting~~	73
~~Reports of Independent Registered Public Accounting Firm~~	74

~~Consolidated Statements of Income~~	77
~~Consolidated Statements of Comprehensive Income~~	78
~~Consolidated Balance Sheets~~	79
~~Consolidated Statements of Cash Flows~~	81
~~Consolidated Statements of Equity~~	82
~~Notes to the Consolidated Financial Statements~~	83
~~Note 1. Business Description and Significant Accounting Policies~~	83
~~Note 2. Revenue~~	92
~~Note 3. Property, Plant and Equipment~~	94
~~Note 4. Jointly Owned Facilities~~	96
~~Note 5. Business Segments~~	97
~~Note 6. Long-term Debt~~	~~102~~
~~Note 7. Notes Payable~~	~~104~~
~~Note 8. Asset Retirement Obligations~~	~~105~~
~~Note 9. Risk Management Activities~~	~~106~~
~~Note 10. Fair Value Measurements~~	~~109~~
~~Note 11. Fair Value of Financial Instruments~~	~~112~~
~~Note 12. Equity~~	~~112~~
~~Note 13. Regulatory Matters~~	~~116~~
~~Note 14. Leases~~	~~120~~
~~Note 15. Income Taxes~~	~~123~~
~~Note 16. Other Comprehensive Income~~	~~126~~
~~Note 17. Supplemental Cash Flow Information~~	~~128~~
~~Note 18. Employee Benefit Plans~~	~~128~~
~~Note 19. Commitments and Contingencies~~	~~135~~
~~Note 20. Guarantees~~	~~139~~
~~Note 21. Discontinued Operations~~	~~140~~
~~Note 22. Quarterly Historical Data (unaudited)~~	~~141~~

Management’s Report on Internal Control over Financial Reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, ~~2019~~,2020, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, ~~2019~~.2020.

Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of December 31, ~~2019.~~2020. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.

Black Hills Corporation

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Black Hills Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the ~~“Company”~~"Company") as of December 31, ~~2019~~2020 and ~~2018,~~2019, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, ~~and equity,~~ for each of the three years in the period ended December 31, ~~2019,~~2020, and the related notes ~~and the schedule listed in the Index at Item 15~~ (collectively referred to as the ~~“financial statements”~~"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2019~~2020 and ~~2018,~~2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2019,~~2020, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in ~~Internal Control--Integrated Framework (2013)~~ issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.

~~Basis for Opinion~~

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

~~Critical Audit Matter~~

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

~~Regulatory Accounting--Impact of Rate Regulation on the Financial Statements--Refer to Note 1 and Note 13 to the financial statements~~

~~Critical Audit Matter Description~~

The Company is subject to cost-of-service regulation and earnings oversight by federal and state utility commissions (collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense).

Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to have been prudently incurred or that the rate regulation process in which rates are determined will always result in rates that produce a full recovery of costs and the return on invested capital.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers. Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

~~How the Critical Audit Matter Was Addressed in the Audit~~

~~Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:~~

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

~~We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.~~

We read relevant regulatory orders issued by the Commissions, procedural memorandums, filings made by the Company, and other publicly available information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions.

We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

~~/s/ DELOITTE & TOUCHE LLP~~

~~Minneapolis, Minnesota~~

~~February 14, 2020~~

~~We have served as the Company’s auditor since 2002.~~

~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~

~~To the shareholders and the Board of Directors of Black Hills Corporation~~

~~Opinion on Internal Control over Financial Reporting~~

~~We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2019, based on criteria established in~~ ~~Internal Control - Integrated Framework (2013)~~ issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in ~~Internal Control - Integrated Framework (2013)~~ ~~issued by COSO.~~

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the ~~consolidated~~Company's internal control over financial ~~statements~~reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) ~~and financial statement schedule~~issued by the Committee of Sponsoring Organizations of the ~~Company as of and for the year ended December 31, 2019,~~Treadway Commission and our report dated February ~~14, 2020~~26, 2021, expressed an unqualified opinion on ~~those consolidated~~the Company's internal control over financial ~~statements and financial statement schedule.~~reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

Critical Audit Matter

Regulatory Accounting - Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 2 to the Financial Statements.

Critical Audit Matter Description

The Company is subject to cost-of-service regulation and earnings oversight by state and federal utility commissions (collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense).

Table of Contents

Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to have been prudently incurred or that the rate regulation process in which rates are determined will not always result in rates that produce a full recovery of costs and the return on invested capital.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) refunds or future reductions in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•We read relevant regulatory orders issued by the Commissions, procedural memorandums, filings made by the Company, and other publicly available information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared it to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions.

•We obtained and evaluated an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or of a future reduction in rates.

•We inspected minutes of the board of directors to identify any evidence that may contradict management’s assertions regarding probability of recovery or refunds. We also inquired of management regarding current year rate filings and new regulatory assets or liabilities.

•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 26, 2021

We have served as the Company's auditor since 2002.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the Board of Directors of Black Hills Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Company and our report dated February 26, 2021, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying ~~Management’s~~Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the ~~Company's~~Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February ~~14, 2020~~26, 2021

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME


Year ended	December 31, 2020		December 31, 2019		December 31, 2018
	(in thousands, except per share amounts)

Revenue	$	1,696,941	$	1,734,900	$	1,754,268

Operating expenses:
Fuel, purchased power and cost of natural gas sold	492,404		570,829		625,610
Operations and maintenance	495,404		495,994		481,706
Depreciation, depletion and amortization	224,457		209,120		196,328
Taxes - property and production	56,373		52,915		51,746
Other operating expenses	0		0		1,841
Total operating expenses	1,268,638		1,328,858		1,357,231

Operating income	428,303		406,042		397,037

Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(144,931)		(139,291)		(141,616)
Interest income	1,461		1,632		1,641
Impairment of investment	(6,859)		(19,741)		0
Other income (expense), net	(2,293)		(5,740)		(1,180)
Total other income (expense)	(152,622)		(163,140)		(141,155)
Income before income taxes	275,681		242,902		255,882
Income tax benefit (expense)	(32,918)		(29,580)		23,667
Income from continuing operations	242,763		213,322		279,549
Net (loss) from discontinued operations	0		0		(6,887)
Net income	242,763		213,322		272,662
Net income attributable to noncontrolling interest	(15,155)		(14,012)		(14,220)
Net income available for common stock	$	227,608	$	199,310	$	258,442

Amounts attributable to common shareholders:
Net income from continuing operations	$	227,608	$	199,310	$	265,329
Net (loss) from discontinued operations	0		0		(6,887)
Net income available for common stock	$	227,608	$	199,310	$	258,442

Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations	$	3.65	$	3.29	$	4.88
(Loss) from discontinued operations	0		0		(0.13)
Total earnings per share of common stock, Basic	$	3.65	$	3.29	$	4.75

Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations	$	3.65	$	3.28	$	4.78
(Loss) from discontinued operations	0		0		(0.12)
Total earnings per share of common stock, Diluted	$	3.65	$	3.28	$	4.66

Weighted average common shares outstanding:
Basic	62,378		60,662		54,420
Diluted	62,439		60,798		55,486

Year ended December 31, 2019 December 31, 2018 December 31, 2017
(in thousands, except per share amounts)

Revenue $ 1,734,900
$ 1,754,268
$ 1,680,266

Operating expenses:
Fuel, purchased power and cost of natural gas sold 570,829
625,610
563,288
Operations and maintenance 495,994
481,706
454,605
Depreciation, depletion and amortization 209,120
196,328
188,246
Taxes - property and production 52,915
51,746
51,578
Other operating expenses —
1,841
5,813
Total operating expenses 1,328,858
1,357,231
1,263,530

Operating income 406,042
397,037
416,736

Other income (expense):
Interest charges -
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) (145,847 ) (143,720 ) (140,533 )
Allowance for funds used during construction - borrowed 6,556
2,104
2,415
Interest income 1,632
1,641
1,016
Allowance for funds used during construction - equity 472
619
2,321
Impairment of investment (19,741 ) —
—
Other income (expense), net (6,212 ) (1,799 ) (213 )
Total other income (expense) (163,140 ) (141,155 ) (134,994 )
Income before income taxes 242,902
255,882
281,742
Income tax benefit (expense) (29,580 ) 23,667
(73,367 )
Income from continuing operations 213,322
279,549
208,375
Net (loss) from discontinued operations —
(6,887 ) (17,099 )
Net income 213,322
272,662
191,276
Net income attributable to noncontrolling interest (14,012 ) (14,220 ) (14,242 )
Net income available for common stock $ 199,310
$ 258,442
$ 177,034

Amounts attributable to common shareholders:
Net income from continuing operations $ 199,310
$ 265,329
$ 194,133
Net (loss) from discontinued operations —
(6,887 ) (17,099 )
Net income available for common stock $ 199,310
$ 258,442
$ 177,034

Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations $ 3.29
$ 4.88
$ 3.65
(Loss) from discontinued operations —
(0.13 ) (0.32 )
Total earnings per share of common stock, Basic $ 3.29
$ 4.75
$ 3.33

Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations $ 3.28
$ 4.78
$ 3.52
(Loss) from discontinued operations —
(0.12 ) (0.31 )
Total earnings per share of common stock, Diluted $ 3.28
$ 4.66
$ 3.21

Weighted average common shares outstanding:
Basic 60,662
54,420
53,221
Diluted 60,798
55,486
55,120

The accompanying Notes to ~~the~~ Consolidated Financial ~~Statements~~Statement s are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


Year ended	December 31, 2020		December 31, 2019		December 31, 2018
	(in thousands)
Net income	$	242,763	$	213,322	$	272,662

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $191, $1,886 and $(660), respectively)	(1,062)		(6,253)		2,155
Benefit plan liability adjustments - prior service costs (net of tax of $0, $2 and $0 respectively)	0		(8)		0
Reclassification adjustment of benefit plan liability - net loss (net of tax of $(958), $434 and $(586), respectively)	1,429		1,179		1,901
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $23, $19 and $43, respectively)	(80)		(58)		(135)
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(287), $(666) and $(599), respectively)	2,564		2,185		2,252
Net unrealized gains (losses) on commodity derivatives (net of tax of $14, $126 and $(228), respectively)	(47)		(422)		755
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(96), $55 and $(31), respectively)	505		(362)		99
Other comprehensive income (loss), net of tax	3,309		(3,739)		7,027

Comprehensive income	246,072		209,583		279,689
Less: comprehensive income attributable to non-controlling interest	(15,155)		(14,012)		(14,220)
Comprehensive income available for common stock	$	230,917	$	195,571	$	265,469

Year ended December 31, 2019 December 31, 2018 December 31, 2017
(in thousands)
Net income $ 213,322
$ 272,662
$ 191,276

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $1,886, $(660) and $1,030, respectively) (6,253 ) 2,155
(1,890 )
Benefit plan liability adjustments - prior service costs (net of tax of $2, $0 and $0, respectively) (8 ) —
—
Reclassification adjustment of benefit plan liability - net loss (net of tax of $434, $(586) and $(585), respectively) 1,179
1,901
1,072
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $19, $43 and $69, respectively) (58 ) (135 ) (128 )
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(666), $(599) and$(1,029) , respectively) 2,185
2,252
1,912
Net unrealized gains (losses) on commodity derivatives (net of tax of $126, $(228) and $(135), respectively) (422 ) 755
231
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $55, $(31) and $154, respectively) (362 ) 99
(516 )
Other comprehensive income (loss), net of tax (3,739 ) 7,027
681

Comprehensive income 209,583
279,689
191,957
Less: comprehensive income attributable to non-controlling interest (14,012 ) (14,220 ) (14,242 )
Comprehensive income available for common stock $ 195,571
$ 265,469
$ 177,715

See Note 16 13for additional disclosures related to Comprehensive Income.

The accompanying Notes to ~~the~~ Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS


	As of
	December 31, 2020		December 31, 2019
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	6,356	$	9,777
Restricted cash and equivalents	4,383		3,881
Accounts receivable, net	265,961		255,805
Materials, supplies and fuel	117,400		117,172
Derivative assets, current	1,848		342
Income tax receivable, net	19,446		16,446

Regulatory assets, current	51,676		43,282
Other current assets	26,221		26,479
Total current assets	493,291		473,184



Property, plant and equipment	7,305,530		6,784,679
Less accumulated depreciation and depletion	(1,285,816)		(1,281,493)
Total property, plant and equipment, net	6,019,714		5,503,186

Other assets:
Goodwill	1,299,454		1,299,454
Intangible assets, net	11,944		13,266

Regulatory assets, non-current	226,582		228,062
Other assets, non-current	37,801		41,305
Total other assets, non-current	1,575,781		1,582,087
TOTAL ASSETS	$	8,088,786	$	7,558,457

As of
December 31, 2019 December 31, 2018
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 9,777
$ 20,776
Restricted cash and equivalents 3,881
3,369
Accounts receivable, net 255,805
269,153
Materials, supplies and fuel 117,172
117,299
Derivative assets, current 342
1,500
Income tax receivable, net 16,446
12,978
Regulatory assets, current 43,282
48,776
Other current assets 26,479
29,982
Total current assets 473,184
503,833

Investments 21,929
41,013

Property, plant and equipment 6,784,679
6,000,015
Less accumulated depreciation and depletion (1,281,493 ) (1,145,136 )
Total property, plant and equipment, net 5,503,186
4,854,879

Other assets:
Goodwill 1,299,454
1,299,454
Intangible assets, net 13,266
14,337
Regulatory assets, non-current 228,062
235,459
Other assets, non-current 19,376
14,352
Total other assets, non-current 1,560,158
1,563,602
TOTAL ASSETS $ 7,558,457
$ 6,963,327

The accompanying Notes to ~~the~~ Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Continued)


	As of
	December 31, 2020		December 31, 2019
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	183,340	$	193,523
Accrued liabilities	243,612		226,767
Derivative liabilities, current	2,044		2,254

Regulatory liabilities, current	25,061		33,507
Notes payable	234,040		349,500
Current maturities of long-term debt	8,436		5,743
Total current liabilities	696,533		811,294

Long-term debt, net of current maturities	3,528,100		3,140,096

Deferred credits and other liabilities:
Deferred income tax liabilities, net	408,624		360,719

Regulatory liabilities, non-current	507,659		503,145
Benefit plan liabilities	150,556		154,472
Other deferred credits and other liabilities	134,667		124,662

Total deferred credits and other liabilities	1,201,506		1,142,998

Commitments, contingencies and guarantees (Note 3)	0		0

Equity:
Stockholders’ equity -
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 62,827,179 and 61,480,658, respectively	62,827		61,481
Additional paid-in capital	1,657,285		1,552,788
Retained earnings	870,738		778,776
Treasury stock at cost - 32,492 and 3,956, respectively	(2,119)		(267)
Accumulated other comprehensive income (loss)	(27,346)		(30,655)
Total stockholders’ equity	2,561,385		2,362,123
Noncontrolling interest	101,262		101,946
Total equity	2,662,647		2,464,069

TOTAL LIABILITIES AND TOTAL EQUITY	$	8,088,786	$	7,558,457

As of
December 31, 2019 December 31, 2018
(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 193,523
$ 210,609
Accrued liabilities 226,767
215,501
Derivative liabilities, current 2,254
947
Regulatory liabilities, current 33,507
29,810
Notes payable 349,500
185,620
Current maturities of long-term debt 5,743
5,743
Total current liabilities 811,294
648,230

Long-term debt, net of current maturities 3,140,096
2,950,835

Deferred credits and other liabilities:
Deferred income tax liabilities, net 360,719
311,331
Regulatory liabilities, non-current 503,145
510,984
Benefit plan liabilities 154,472
145,147
Other deferred credits and other liabilities 124,662
109,377
Total deferred credits and other liabilities 1,142,998
1,076,839

Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)

Equity:
Stockholders’ equity -
Common stock $1 par value; 100,000,000 shares authorized; issued: 61,480,658 and 60,048,567, respectively 61,481
60,049
Additional paid-in capital 1,552,788
1,450,569
Retained earnings 778,776
700,396
Treasury stock at cost - 3,956 and 44,253, respectively (267 ) (2,510 )
Accumulated other comprehensive income (loss) (30,655 ) (26,916 )
Total stockholders’ equity 2,362,123
2,181,588
Noncontrolling interest 101,946
105,835
Total equity 2,464,069
2,287,423

TOTAL LIABILITIES AND TOTAL EQUITY $ 7,558,457
$ 6,963,327

The accompanying Notes to ~~the~~ Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


Year ended	December 31, 2020		December 31, 2019		December 31, 2018
	(in thousands)
Operating activities:
Net income	$	242,763	$	213,322	$	272,662
Loss from discontinued operations, net of tax	0		0		6,887
Income from continuing operations	242,763		213,322		279,549
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	224,457		209,120		196,328
Deferred financing cost amortization	7,883		7,838		7,845
Impairment of investment	6,859		19,741		0
Stock compensation	5,373		12,095		12,390
Deferred income taxes	38,091		38,020		(24,239)
Employee benefit plans	11,997		12,406		14,068
Other adjustments, net	11,669		16,485		5,836
Change in certain operating assets and liabilities:
Materials, supplies and fuel	2,755		2,052		(2,919)
Accounts receivable and other current assets	(10,843)		7,578		(45,966)
Accounts payable and other current liabilities	24,659		(34,906)		5,305
Regulatory assets - current	(5,047)		23,619		33,608
Regulatory liabilities - current	(10,706)		(15,158)		18,533
Contributions to defined benefit pension plans	(12,700)		(12,700)		(12,700)
Other operating activities, net	4,653		6,001		6,689
Net cash provided by operating activities of continuing operations	541,863		505,513		494,327
Net cash provided by (used in) operating activities of discontinued operations	0		0		(5,516)
Net cash provided by operating activities	541,863		505,513		488,811

Investing activities:
Property, plant and equipment additions	(767,404)		(818,376)		(457,524)
Purchase of investment	0		0		(24,429)
Other investing activities	5,740		2,166		(4,281)
Net cash (used in) investing activities of continuing operations	(761,664)		(816,210)		(486,234)
Net cash provided by investing activities of discontinued operations	0		0		20,385
Net cash (used in) investing activities	(761,664)		(816,210)		(465,849)

Financing activities:
Dividends paid on common stock	(135,439)		(124,647)		(106,591)
Common stock issued	99,278		101,358		300,834
Net (payments) borrowings of short-term debt	(115,460)		163,880		(25,680)
Long-term debt - issuance	400,000		1,100,000		700,000
Long-term debt - repayments	(8,597)		(905,743)		(854,743)
Distributions to noncontrolling interests	(15,839)		(17,901)		(19,617)
Other financing activities	(7,061)		(16,737)		(11,260)
Net cash provided by (used in) financing activities	216,882		300,210		(17,057)

Net change in cash, restricted cash and cash equivalents	(2,919)		(10,487)		5,905

Cash, restricted cash and cash equivalents beginning of year	13,658		24,145		18,240
Cash, restricted cash and cash equivalents end of year	$	10,739	$	13,658	$	24,145

Supplemental cash flow information:
Cash (paid) refunded during the period for continuing operations:
Interest (net of amounts capitalized)	$	(136,549)	$	(131,774)	$	(137,965)
Income taxes	$	2,172	$	4,682	$	(14,730)

Non-cash investing and financing activities from continuing operations:
Accrued property, plant and equipment purchases at December 31	$	72,215	$	91,491	$	69,017
Increase in capitalized assets associated with asset retirement obligations	$	4,774	$	5,044	$	2,625

Year ended December 31, 2019 December 31, 2018 December 31, 2017
(in thousands)
Operating activities:
Net income $ 213,322
$ 272,662
$ 191,276
Loss from discontinued operations, net of tax —
6,887
17,099
Income from continuing operations 213,322
279,549
208,375
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization 209,120
196,328
188,246
Deferred financing cost amortization 7,838
7,845
8,261
Impairment of investment 19,741
—
—
Stock compensation 12,095
12,390
7,626
Deferred income taxes 38,020
(24,239 ) 80,992
Employee benefit plans 12,406
14,068
10,141
Other adjustments, net 16,485
5,836
(4,773 )
Change in certain operating assets and liabilities:
Materials, supplies and fuel 2,052
(2,919 ) (10,089 )
Accounts receivable and other current assets 7,578
(45,966 ) 4,534
Accounts payable and other current liabilities (34,906 ) 5,305
(28,222 )
Regulatory assets - current 23,619
33,608
(15,407 )
Regulatory liabilities - current (15,158 ) 18,533
(4,536 )
Contributions to defined benefit pension plans (12,700 ) (12,700 ) (27,700 )
Other operating activities, net 6,001
6,689
(8,418 )
Net cash provided by operating activities of continuing operations 505,513
494,327
409,030
Net cash provided by (used in) operating activities of discontinued operations —
(5,516 ) 19,231
Net cash provided by operating activities 505,513
488,811
428,261

Investing activities:
Property, plant and equipment additions (818,376 ) (457,524 ) (326,010 )
Purchase of investment —
(24,429 ) —
Other investing activities 2,166
(4,281 ) 1,011
Net cash (used in) investing activities of continuing operations (816,210 ) (486,234 ) (324,999 )
Net cash provided by investing activities of discontinued operations —
20,385
7,881
Net cash (used in) investing activities (816,210 ) (465,849 ) (317,118 )

Financing activities:
Dividends paid on common stock (124,647 ) (106,591 ) (96,744 )
Common stock issued 101,358
300,834
4,408
Net (payments) borrowings of short-term debt 163,880
(25,680 ) 114,700
Long-term debt - issuance 1,100,000
700,000
—
Long-term debt - repayments (905,743 ) (854,743 ) (105,743 )
Distributions to noncontrolling interests (17,901 ) (19,617 ) (18,397 )
Other financing activities (16,737 ) (11,260 ) (6,919 )
Net cash provided by (used in) financing activities 300,210
(17,057 ) (108,695 )

Net change in cash, restricted cash and cash equivalents (10,487 ) 5,905
2,448

Cash, restricted cash and cash equivalents beginning of year 24,145
18,240
15,792
Cash, restricted cash and cash equivalents end of year $ 13,658
$ 24,145
$ 18,240

~~See~~ ~~Note 17~~ ~~for supplemental disclosure of cash flow information.~~

The accompanying Notes to ~~the~~ Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

Common Stock Treasury Stock
(in thousands except share amounts) Shares Value Shares Value Additional Paid in Capital Retained Earnings AOCI Non controlling Interest Total
Balance at December 31, 2016 53,397,467
$ 53,397
15,258
$ (791 ) $ 1,138,982
$ 457,934
$ (34,883 ) $ 115,495
$ 1,730,134
Net income (loss) available for common stock —
—
—
—
—
177,034
—
14,242
191,276
Other comprehensive income (loss), net of tax —
—
—
—
—
—
681
—
681
Reclassification of certain tax effects from AOCI —
—
—
—
—
7,000
(7,000 ) —
—
Dividends on common stock —
—
—
—
—
(96,744 ) —
—
(96,744 )
Share-based compensation 134,266
134
23,806
(1,515 ) 8,948
—
—
—
7,567
Tax effect of share-based compensation —
—
—
—
533
3,184
—
—
3,717
Issuance costs —
—
—
—
(189 ) —
—
—
(189 )
Dividend reinvestment and stock purchase plan 48,253
49
—
—
3,107
—
—
—
3,156
Distributions to noncontrolling interest —
—
—
—
(1,096 ) 209
—
(18,505 ) (19,392 )
Balance at December 31, 2017 53,579,986
$ 53,580
39,064
$ (2,306 ) $ 1,150,285
$ 548,617
$ (41,202 ) $ 111,232
$ 1,820,206
Net income (loss) available for common stock —
—
—
—
—
258,442
—
14,220
272,662
Other comprehensive income (loss), net of tax —
—
—
—
—
—
7,027
—
7,027
Reclassification of certain tax effects from AOCI —
—
—
—
—
—
740
—
740
Reclassification to regulatory asset —
—
—
—
—
—
6,519
—
6,519
Dividends on common stock —
—
—
—
—
(106,591 ) —
—
(106,591 )
Share-based compensation 92,830
93
5,189
(204 ) 7,301
—
—
—
7,190
Issuance of common stock 6,371,690
6,372
—
—
292,628
—
—
—
299,000
Issuance costs —
—
—
—
(15 ) —
—
—
(15 )
Dividend reinvestment and stock purchase plan 4,061
4
—
—
216
—
—
—
220
Other stock transactions —
—
—
—
154
(72 ) —
—
82
Redemption of and distributions to noncontrolling interest —
—
—
—
—
—
—
(19,617 ) (19,617 )
Balance at December 31, 2018 60,048,567
$ 60,049
44,253
$ (2,510 ) $ 1,450,569
$ 700,396
$ (26,916 ) $ 105,835
$ 2,287,423
Net income (loss) available for common stock —
—
—
—
—
199,310
—
14,012
213,322
Other comprehensive income (loss), net of tax —
—
—
—
—
—
(3,739 ) —
(3,739 )
Dividends on common stock —
—
—
—
—
(124,647 ) —
—
(124,647 )
Share-based compensation 103,759
104
(40,297 ) 2,243
4,729
—
—
—
7,076
Issuance of common stock 1,328,332
1,328
—
—
98,672
—
—
—
100,000
Issuance costs —
—
—
—
(1,182 ) —
—
—
(1,182 )
Other —
—
—
—
—
327
—
—
327
Implementation of ASU 2016-02 Leases —
—
—
—
—
3,390
—
—
3,390
Distributions to noncontrolling interest —
—
—
—
—
—
—
(17,901 ) (17,901 )
Balance at December 31, 2019 61,480,658
$ 61,481
3,956
$ (267 ) $ 1,552,788
$ 778,776
$ (30,655 ) $ 101,946
$ 2,464,069

~~__________________~~


	Common Stock			Treasury Stock
(in thousands except share amounts)	Shares	Value		Shares	Value		Additional Paid in Capital		Retained Earnings		AOCI		Non controlling Interest		Total
Balance at December 31, 2017	53,579,986	$	53,580	39,064	$	(2,306)	$	1,150,285	$	548,617	$	(41,202)	$	111,232	$	1,820,206
Net income available for common stock	—	—		—	—		—		258,442		—		14,220		272,662
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		7,027		—		7,027
Reclassification of certain tax effects from AOCI	—	—		—	—		—		—		740		—		740
Reclassification to regulatory asset	—	—		—	—		—		—		6,519		—		6,519
Dividends on common stock ($1.93 per share)	—	—		—	—		—		(106,591)		—		—		(106,591)
Share-based compensation	92,830	93		5,189	(204)		7,301		—		—		—		7,190

Issuance of common stock	6,371,690	6,372		—	—		292,628		—		—		—		299,000
Issuance costs	—	—		—	—		(15)		—		—		—		(15)
Dividend reinvestment and stock purchase plan	4,061	4		—	—		216		—		—		—		220
Other stock transactions	—	—		—	—		154		(72)		—		—		82
Distributions to noncontrolling interest	—	—		—	—		—		—		—		(19,617)		(19,617)
Balance at December 31, 2018	60,048,567	$	60,049	44,253	$	(2,510)	$	1,450,569	$	700,396	$	(26,916)	$	105,835	$	2,287,423
Net income available for common stock	—	—		—	—		—		199,310		—		14,012		213,322
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		(3,739)		—		(3,739)
Dividends on common stock ($2.05 per share)	—	—		—	—		—		(124,647)		—		—		(124,647)
Share-based compensation	103,759	104		(40,297)	2,243		4,729		—		—		—		7,076

Issuance of common stock	1,328,332	1,328		—	—		98,672		—		—		—		100,000
Issuance costs	—	—		—	—		(1,182)		—		—		—		(1,182)

Other	—	—		—	—		—		327		—		—		327
Implementation of ASU 2016-02 Leases	—	—		—	—		—		3,390		—		—		3,390
Distributions to noncontrolling interest	—	—		—	—		—		—		—		(17,901)		(17,901)
Balance at December 31, 2019	61,480,658	$	61,481	3,956	$	(267)	$	1,552,788	$	778,776	$	(30,655)	$	101,946	$	2,464,069
Net income available for common stock	—	—		—	—		—		227,608		—		15,155		242,763
Other comprehensive income (loss), net of tax	—	—		—	—		—		—		3,309		—		3,309
Dividends on common stock ($2.17 per share)	—	—		—	—		—		(135,439)		—		—		(135,439)
Share-based compensation	123,578	123		28,536	(1,852)		6,923		—		—		—		5,194

Issuance of common stock	1,222,943	1,223		—	—		98,777		—		—		—		100,000
Issuance costs	—	—		—	—		(1,203)		—		—		—		(1,203)

Implementation of ASU 2016-13 Financial Instruments - - Credit Losses	—	—		—	—		—		(207)		—		—		(207)

Distributions to noncontrolling interest	—	—		—	—		—		—		—		(15,839)		(15,839)
Balance at December 31, 2020	62,827,179	$	62,827	32,492	$	(2,119)	$	1,657,285	$	870,738	$	(27,346)	$	101,262	$	2,662,647

~~Dividends per share paid were~~ ~~$2.05~~, ~~$1.93~~ ~~and~~ ~~$1.81~~ ~~for the years ended~~ ~~December 31, 2019~~, ~~2018~~ ~~and~~ ~~2017, respectively.~~

The accompanying Notes to ~~the~~ Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

~~NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS~~Notes to Consolidated Financial Statements

December 31, 2020, 2019, ~~2018~~ and 2018

~~2017~~

(1) BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES


( 1)	~~BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES~~

Business Description

Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.

Segment Reporting

Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States.

Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming.

~~Most~~Both of our non-utility business segments support our Electric Utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 518.

On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment ~~assets and liabilities were classified as held for sale and the~~ results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued ~~operations in 2018 or 2017. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded.~~operations. Unless otherwise noted, the amounts presented in the accompanying ~~notes~~Notes to ~~the consolidated financial statements~~Consolidated Financial Statements relate to the Company’s continuing operations. ~~For more information on discontinued operations, see~~ ~~Note 21~~.

Use of Estimates and Basis of Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide 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.

The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the year ended December 31, 2020, there were no material adverse impacts on the Company’s results of operations.

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 518.

Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility ~~generating~~generation facility, wind ~~project~~farm or transmission tie. See Note 46 for additional information.

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Variable Interest Entities

We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements.

A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated.

Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 1214.

Cash and Cash Equivalents and Restricted Cash

We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash.

Accounts Receivable and Allowance for ~~Doubtful Accounts~~Credit Losses

Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, ~~municipal~~transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of ~~write-offs and~~ allowance for ~~doubtful accounts.~~credit losses. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and ~~coal.~~coal primarily to affiliates or regional utilities.

We maintain an allowance for ~~doubtful accounts~~credit losses which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility.

In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for ~~doubtful accounts~~credit losses to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.

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Following is a summary of accounts receivable as of December 31 (in thousands):


2020	Billed Accounts Receivable		Unbilled Revenue		Less Allowance for Credit Losses		Accounts Receivable, net
Electric Utilities	$	45,841	$	32,915	$	(1,269)	$	77,487
Gas Utilities	95,592		93,150		(5,734)		183,008
Power Generation	1,837		0		0		1,837
Mining	2,511		0		0		2,511
Corporate	1,118		0		0		1,118
Total	$	146,899	$	126,065	$	(7,003)	$	265,961


2019	Accounts Receivable, Trade		Unbilled Revenue		Less Allowance for Doubtful Accounts			Accounts Receivable, net		2019	Billed Accounts Receivable		Unbilled Revenue		Less Allowance for Credit Losses		Accounts Receivable, net
Electric Utilities	$	41,428	$	33,886	$	(592	)	$	74,722	Electric Utilities	$	41,428	$	33,886	$	(592)	$	74,722
Gas Utilities	97,607		79,616		(1,683		)	175,540		Gas Utilities	97,607		79,616		(1,683)		175,540
Power Generation	2,164		—		—			2,164		Power Generation	2,164		0		0		2,164
Mining	2,277		—		—			2,277		Mining	2,277		0		0		2,277
Corporate	1,271		—		(169		)	1,102		Corporate	1,271		0		(169)		1,102
Total	$	144,747	$	113,502	$	(2,444	)	$	255,805	Total	$	144,747	$	113,502	$	(2,444)	$	255,805

2018 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net
Electric Utilities $ 39,721
$ 35,125
$ (448 ) $ 74,398
Gas Utilities 96,123
90,521
(2,592 ) 184,052
Power Generation 1,876
—
—
1,876
Mining 3,988
—
—
3,988
Corporate 5,008
—
(169 ) 4,839
Total $ 146,716
$ 125,646
$ (3,209 ) $ 269,153

Changes to allowance for ~~doubtful accounts~~credit losses for the years ended December 31, were as follows (in thousands):


	Balance at Beginning of Year		Additions Charged to Costs and Expenses			Recoveries and Other Additions		Write-offs and Other Deductions		Balance at End of Year
2020	$	2,444	$	8,927	(a)	$	4,728	$	(9,096)	$	7,003
2019	$	3,209	$	5,795		$	3,942	$	(10,502)	$	2,444
2018	$	3,081	$	6,859		$	4,092	$	(10,823)	$	3,209

Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year
2019 $ 3,209
$ 5,795
$ 3,942
$ (10,502 ) $ 2,444
2018 $ 3,081
$ 6,859
$ 4,092
$ (10,823 ) $ 3,209
2017 $ 2,392
$ 4,926
$ 8,262
$ (12,499 ) $ 3,081
_________________

(a) Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections due to non-payment for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the year ended December 31, 2020 by an incremental $3.3 million. The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 11.

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):


	2020		2019
Materials and supplies	$	85,250	$	82,809
Fuel	1,531		2,425
Natural gas in storage	30,619		31,938
Total materials, supplies and fuel	$	117,400	$	117,172

2019 2018
Materials and supplies $ 82,809
$ 75,081
Fuel - Electric Utilities 2,425
2,850
Natural gas in storage 31,938
39,368
Total materials, supplies and fuel $ 117,172
$ 117,299



☒	~~ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~

	~~For the fiscal year ended~~	~~December 31, 2019~~
	Or
☐	~~TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~

	~~For the transition period from ___________________ to __________________~~

	~~Commission File Number~~	~~001-31303~~



~~Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.~~
	~~Yes~~	☒	No	Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

~~Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.~~
	~~Yes~~	☐	No	☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
	~~Yes~~	☒	No	☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
	~~Yes~~	☒	No	☐



~~Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).~~
	~~Yes~~	☐		No	☒

~~The aggregate market value of the voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s~~
~~most recently completed second fiscal quarter, June 30, 2019, was~~			~~$4,727,278,183~~



Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Class	Outstanding at January 31, ~~2020~~2021
Common stock, $1.00 par value	~~61,475,403~~62,794,490	shares


ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	62
	Management’s Report on Internal Controls Over Financial Reporting	62
	Reports of Independent Registered Public Accounting Firm	63
	Consolidated Statements of Income	66
	Consolidated Statements of Comprehensive Income	67
	Consolidated Balance Sheets	68
	Consolidated Statements of Cash Flows	70
	Consolidated Statements of Equity	71
	Notes to Consolidated Financial Statements	72
	Note 1. Business Description and Significant Accounting Policies	72
	Note 2 . Regulatory Matters	81
	Note 3. Commitments, Contingencies and Guarantees	85
	Note 4 . Revenue	89
	Note 5 . Property, Plant and Equipment	92
	Note 6 . Jointly Owned Facilities	93
	Note 7 . Asset Retirement Obligations	95
	Note 8 . Leases	95
	Note 9. Debt and Credit Facilities	97
	Note 1 0 . Stockholders ’Equity	100
	Note 11. Risk Management and Derivatives	101
	Note 12. Fair Value Measurements	100
	Note 1 3 . Other Comprehensive Income	106
	Note 14. Variable Interest Entit y	104
	Note 1 5 . Employee Benefit Plans	108
	Note 16. Share-based Compensation Plans	114
	Note 1 7 . Income Taxes	116
	Note 18. Business Segment Information	121
	Note 19. Subsequent Event	124
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	~~143~~125
ITEM 9A.	CONTROLS AND PROCEDURES	~~143~~125
ITEM 9B.	OTHER INFORMATION	~~143~~125
Part III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	~~144~~126
ITEM 11.	EXECUTIVE COMPENSATION	~~144~~126
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	~~144~~126
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	~~144~~126
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	~~144~~126
Part IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	~~145~~127
ITEM 16.	FORM 10-K SUMMARY	~~148~~130
SIGNATURES		~~149~~131



		Page
GLOSSARY OF TERMS AND ABBREVIATIONS		34
WEBSITE ACCESS TO REPORTS		89
FORWARD-LOOKING INFORMATION		89
Part I
ITEMS 1. and 2.	BUSINESS AND PROPERTIES	910
	History and Organization	910
	Electric Utilities	910
	Gas Utilities	1714
	Utility Regulation Characteristics	2217
	Power Generation	2318
	Mining	2519
	Environmental Matters	2721
	Other Properties	2822
	~~Employees~~Human Capital Resources	2922
ITEM 1A.	RISK FACTORS	2924
ITEM 1B.	UNRESOLVED STAFF COMMENTS	3731
ITEM 3.	LEGAL PROCEEDINGS	3731
ITEM 4.	MINE SAFETY DISCLOSURES	3731
INFORMATION ABOUT OUR EXECUTIVE OFFICERS		3832
Part II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	3933
ITEM 6.	SELECTED FINANCIAL DATA	4033
~~ITEMS~~ITEM 7. ~~and 7A.~~	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ~~AND~~	34
	Executive Summary	34
	Key Elements of our Business Strategy	34
	Prospective Information	37
	Company Highlights	37
	Results of Operations - Consolidated Summary and Overview	41
	Non-GAAP Financial Measure	42
	Electric Utilities	43
	Gas Utilities	46
	Power Generation	48
	Mining	49
	Corporate and Other	49
	Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)	50
	Liquidity and Capital Resources	50
	Cash Flow Activities	51
	Capital Sources	52
	Credit Ratings	54
	Capital Requirements	55
	Critical Accounting Policies Involving Significant Estimates	56
	New Accounting Pronouncements	59
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	4260



AC		Alternating Current
AFUDC		Allowance for Funds Used During Construction
AOCI		Accumulated Other Comprehensive Income (Loss)
Aquila Transaction		Our July 14, 2008 acquisition of five utilities from Aquila, Inc.
APSC		Arkansas Public Service Commission
Arkansas Gas		Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
ARO		Asset Retirement Obligations
ASC		Accounting Standards Codification
ASU		Accounting Standards Update as issued by the FASB
ATM		At-the-market equity offering program
Availability		The availability factor of a power plant is the percentage of the time that it is available to provide energy.
~~Basin Electric~~BHC		~~Basin Electric Power Cooperative~~
~~BHC~~	Black Hills Corporation; the Company
BHSC		Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Colorado IPP		Black Hills Colorado IPP, LLC, a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric Generation		Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.
Black Hills Energy		The name used to conduct the business of our utility companies
Black Hills Energy Services		Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings		Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings		Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming		Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
BLM		United States Bureau of Land Management
Btu		British thermal unit
Busch Ranch I		The 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm.
Busch Ranch II		The 60 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a power purchase agreement expiring in November 2044.
~~CAPP~~CARES Act		~~Customer Appliance Protection Plan,~~Coronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which ~~provides appliance repair services~~is a tax and spending package intended to ~~residential natural gas customers through on-going monthly service agreements. The consolidation~~provide additional economic relief and address the impact of the ~~existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.~~COVID-19 pandemic.
CFTC		United States Commodity Futures Trading Commission
Cheyenne Prairie		~~132 MW natural-gas fired generating facility jointly owned by~~Cheyenne Prairie Generating Station serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric ~~in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.~~and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW).
Chief Operating Decision Maker (CODM)		Chief Executive Officer
Choice Gas Program		Regulator approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing the unbundling of the commodity service from the distribution delivery service.
~~City~~CIAC		Contribution in Aid of ~~Gillette~~	~~Gillette, Wyoming~~Construction
City of Cheyenne		Cheyenne, Wyoming



City of Colorado Springs		Colorado Springs, Colorado
City of Gillette		Gillette, Wyoming
Colorado Electric		Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas		Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Common Use System (CUS)		The Common Use System is a ~~joint~~jointly operated transmission system we participate in with Basin Electric Power Cooperative and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230-kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming.
Consolidated Indebtedness to Capitalization Ratio		Any Indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net-worth (excluding noncontrolling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day (CDD)		A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
Corriedale		~~Wind project near Cheyenne, Wyoming, that will be a~~The 52.5 MW wind farm near Cheyenne, Wyoming, jointly owned by South Dakota Electric and Wyoming Electric, ~~and will serve~~serving as the dedicated wind energy supply to the Renewable Ready program.
~~CPCN~~COVID-19		The official name for the 2019 novel coronavirus disease announced on February 11, 2020, by the World Health Organization, that is causing a global pandemic.
CPCN		Certificate of Public Convenience and Necessity
CPP		Clean Power Plan
CP Program		Commercial Paper Program
CPUC		Colorado Public Utilities Commission
CT		Combustion ~~turbine~~Turbine
CTII		The 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette.
Cushion Gas		The portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability.
CVA		Credit Valuation Adjustment
DC		Direct ~~current~~Current
Dividend payout ratio		Annual dividends paid on common stock divided by net income from continuing operations available for common stock
~~Dodd-Frank~~DRSPP		~~Dodd-Frank Wall Street Reform and Consumer Protection Act~~
~~DSM~~	~~Demand Side Management~~
~~DRSPP~~	Dividend Reinvestment and Stock Purchase Plan
~~Dth~~DSM		Demand Side Management
Dth		Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu).
EBITDA		Earnings before interest, taxes, depreciation and amortization, a non-GAAP measurement
ECA		Energy Cost Adjustment ~~-- adjustments~~is an adjustment that ~~allow~~allows us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
Economy Energy		Purchased energy that costs less than that produced with the utilities’ owned generation.
~~EIA~~EECR		Energy Efficiency Cost Recovery is an adjustment mechanism that allows us to recover from customers the costs associated with providing energy efficiency programs.
EIA		Environmental Improvement Adjustment --is an annual adjustment mechanism that allows us to recover from customers eligible investments in, and expense related to, new environmental measures.
EPA		United States Environmental Protection Agency


Equity Unit			Each Equity Unit ~~has~~had a stated amount of $50, consisting of a purchase contract issued by BHC to purchase shares of BHC common stock and a 1/20, or 5% undivided beneficial ownership interest in $1,000 principal amount of BHC ~~RSNs due 2028.~~remarketable junior subordinated notes issued on November 23, 2015 and retired on August 17, 2018. On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015.
EWG			Exempt Wholesale Generator
FASB			Financial Accounting Standards Board



~~FDIC~~FERC		~~Federal Deposit Insurance Corporation~~
~~FERC~~	United States Federal Energy Regulatory Commission
Fitch		Fitch Ratings Inc.
GAAP		Accounting principles generally accepted in the United States of America
GCA		Gas Cost Adjustment ~~-- adjustments~~is an adjustment that ~~allow~~allows us to pass the prudently-incurred cost of gas and certain services through to customers.
GHG		Greenhouse gases
Global Settlement		Settlement with a ~~utilities~~utility’s commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Happy Jack		Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Heating Degree Day (HDD)		A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServe		We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
ICFR		Internal Controls Over Financial Reporting
Iowa Gas		Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP		Independent ~~power producer~~Power Producer
~~IRS~~IRC		Internal Revenue Code
IRS		United States Internal Revenue Service
ITC		Investment ~~tax credit~~Tax Credit

Kansas Gas		Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
kV		~~Kilovolt~~
~~LIBOR~~kV		Kilovolt
LIBOR		London Interbank Offered Rate
Mcf		Thousand cubic feet
Mcfd		Thousand cubic feet per day
MDU		Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
MEAN		Municipal Energy Agency of Nebraska
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British thermal units
Moody’s		Moody’s Investors Service, Inc.
MSHA		Mine Safety and Health Administration
MTPSC		Montana Public Service Commission
MW		Megawatts
MWh		Megawatt-hours
N/A		Not Applicable
NAV		Net Asset Value
Nebraska Gas		Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
~~NERC~~Neil Simpson II		A mine-mouth, coal-fired power plant owned and operated by South Dakota Electric with a total capacity of 90 MW located at our Gillette, Wyoming energy complex.


NERC			North American Electric Reliability Corporation
NO_x			Nitrogen oxide
NOL			Net ~~operating loss~~Operating Loss
NPSC			Nebraska Public Service Commission
NYSE			New York Stock Exchange
~~OPEB~~OCI			Other Comprehensive Income
OPEB			Other Post-Employment Benefits
OSHA			Occupational Safety & Health Administration
OSM			United States Department of the Interior’s Office of Surface Mining


PacifiCorp
~~PacifiCorp~~	PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway.
PCA		Power Cost Adjustment --is an annual adjustment mechanism that allows us to pass a portion of prudently-incurred delivered power costs, including fuel, purchased capacity and energy, and transmission costs, through to customers.
PCCA		Power Capacity Cost Adjustment --is an annual adjustment that allows us to pass the prudently-incurred purchased capacity costs, incremental to costs included in base rates, through to customers.
Peak View		The 60 MW wind ~~generating project~~farm owned by Colorado ~~Electric, placed in service on November 7, 2016 and adjacent to Busch Ranch I.~~Electric.
PPA		Power Purchase Agreement
PRPA		Platte River Power Authority
PSA		Power Sales Agreement
~~PSCo~~		~~Public Service Company of Colorado~~
Pueblo Airport Generation	The 420 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (220 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012.
PTC		Production ~~tax credit~~Tax Credit
PUHCA 2005		Public Utility Holding Company Act of 2005
Ready		The Company’s branding platform which emphasizes that we will 1) prioritize our customers; 2) act as a thoughtful, responsible leader; 3) listen first and lead with a focus on relationships; and 4) be creative in our approach to solutions.
Renewable Advantage		The 200 MW solar facility project to be constructed in Pueblo County, Colorado. The project aims to lower customer energy costs and provide economic and environmental benefits to Colorado Electric’s customers and communities. This project, which was approved by the CPUC in September 2020, will be owned by a third-party renewable energy developer with Colorado Electric purchasing all of the energy generated at the facility under the terms of a 15-year PPA. The project is expected to be placed in service in 2023.
Renewable Ready		Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers in South Dakota and Wyoming.
RESA		Renewable Energy Standard Adjustment is an incremental retail rate limited to 2% for Colorado Electric customers that provides funding for renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard.
Revolving Credit Facility		Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 30, 2018, and now terminates on July 30, 2023.
~~Renewable Ready~~RMNG		Voluntary renewable energy subscription program for large commercial, industrial and governmental agency customers. The Corriedale wind project will provide 52.5 MW of energy for Renewable Ready subscribers in Wyoming and western South Dakota.
~~RMNG~~	Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy).
~~RSNs~~		~~Remarketable junior subordinated notes, issued on November 23, 2015 and retired on August 17, 2018.~~
~~SCADA~~SDPUC		~~Supervisory control and data acquisition~~
~~SDPUC~~	South Dakota Public Utilities Commission
SEC		United States Securities and Exchange Commission
Service Guard Comfort Plan		~~Home~~Appliance protection plan that provides home appliance repair ~~product offering for both natural gas and electric residential customers~~services through on-going monthly service ~~agreements. The consolidation of the existing Service Guard and CAPP plans into the revamped Service Guard Comfort Plan is currently underway across our service territories.~~agreements to residential utility customers.
~~Service Guard Comfort Plan~~		~~New plan that will consolidate Service Guard and CAPP and provide similar services.~~
Silver Sage	Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO₂		Sulfur dioxide
S&P		Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
SPP		Southwest Power Pool, Inc. which oversees the bulk electric grid and wholesale power market in the central United States


SourceGas Transaction			On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing.
South Dakota Electric			Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SSIR			System Safety and Integrity Rider
System Peak Demand			Represents the highest point of retail customer usage for a single hour.
TCA			Transmission Cost Adjustment --is an annual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the next rate review.
TCJA			Tax Cuts and Jobs Act enacted on December 22, 2017



Tech Services	Non-regulated product lines ~~within Black Hills Corporation~~delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining ~~customer-owner~~customer-owned gas infrastructure facilities, typically through one-time contracts.
~~TFA~~Top of Iowa		Northern Iowa Windpower, LLC, a 80 MW wind farm located near Joice, Iowa, owned by Black Hills Electric Generation and operated by a third-party. We sell the wind energy generated in the MISO market.
TFA		Transmission Facility Adjustment --is an annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers.
~~VEBA~~Transmission Tie		South Dakota Electric owns 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western and eastern United States, respectively. Basin Electric Power Cooperative owns the remaining ownership percentage. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West.
Utilities		Black Hills’ Electric and Gas Utilities
VEBA		Voluntary Employee Benefit Association
VIE		Variable Interest Entity
~~WDEQ~~WECC		~~Wyoming Department of Environmental Quality~~
~~WECC~~	Western Electricity Coordinating Council
Wind Capacity Factor		Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
Working Capacity		Total gas storage capacity minus cushion gas
WPSC		Wyoming Public Service Commission
WRDC		Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities (doing business as Black Hills Energy).
Wygen I		A mine-mouth, coal-fired generating facility with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wygen II		A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex.
Wygen III		A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 110 MW located at our Gillette, Wyoming energy complex. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23%.
Wyodak Plant		The 362 MW mine-mouth, coal-fired generating facility near Gillette, Wyoming, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility.
Wyoming Electric		Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas		Black Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).


	As of December 31,
Customers at End of Year	2020	2019	2018
Residential	184,872	183,232	181,459
Commercial	30,225	29,921	29,299
Industrial	83	83	84
Other	1,017	1,024	1,030
Total Electric Customers at End of Year	216,197	214,260	211,872


	System Peak Demand (in MW)
	2020		2019		2018
	Summer	Winter	Summer	Winter	Summer	Winter
Colorado Electric	401	297	422	297	413	313
South Dakota Electric	378	304	335	320	355	314
Wyoming Electric	271	246	265	247	254	238


~~(a)~~	The Colorado Electric July 2019 summer peak load of 422 surpassed previous summer peak record load of 413 set in June 2018. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011.


~~(b)~~	The Wyoming Electric July 2019 summer peak load of 265 surpassed previous summer peak record load of 254 set in July 2018. The December 2019 winter peak load of 247 surpassed the previous winter peak record load of 238 set in December 2018.


Unit	Fuel Type	Location	Ownership Interest %	Owned Capacity (MW)	In Service Date	Unit	Fuel Type		Location		Ownership Interest % (d)		Owned Capacity (MW)		In Service Date
Colorado Electric:						Colorado Electric:
Busch Ranch I^(a)	Wind	Pueblo, Colorado	50%	14.5	2012	Busch Ranch I (a)	Wind		Pueblo, Colorado		50%		14.5		2012
Peak View ^(b)	Wind	Pueblo, Colorado	100%	60.0	2016	Peak View (b)	Wind		Pueblo, Colorado		100%		60.0		2016
Pueblo Airport Generation	Gas	Pueblo, Colorado	100%	180.0	2011	Pueblo Airport Generation	Gas		Pueblo, Colorado		100%		180.0		2011
Pueblo Airport Generation CT	Gas	Pueblo, Colorado	100%	40.0	2016	Pueblo Airport Generation CT	Gas		Pueblo, Colorado		100%		40.0		2016
AIP Diesel	Oil	Pueblo, Colorado	100%	10.0	2001	AIP Diesel	Oil		Pueblo, Colorado		100%		10.0		2001
Diesel #1 and #3-5	Oil	Pueblo, Colorado	100%	8.0	1964	Diesel #1 and #3-5	Oil		Pueblo, Colorado		100%		8.0		1964
Diesel #1-5	Oil	Rocky Ford, Colorado	100%	10.0	1964	Diesel #1-5	Oil		Rocky Ford, Colorado		100%		10.0		1964
South Dakota Electric:						South Dakota Electric:
Cheyenne Prairie ^(c)	Gas	Cheyenne, Wyoming	58%	55.0	2014
Cheyenne Prairie						Cheyenne Prairie	Gas		Cheyenne, Wyoming		58%		55.0		2014
Corriedale (c)						Corriedale (c)	Wind		Cheyenne, Wyoming		62%		32.5		2020
Wygen III^(d)	Coal	Gillette, Wyoming	52%	57.2	2010	Coal		Gillette, Wyoming		52%		57.2		2010
Neil Simpson II	Coal	Gillette, Wyoming	100%	90.0	1995	Neil Simpson II	Coal		Gillette, Wyoming		100%		90.0		1995
Wyodak Plant ^(e)	Coal	Gillette, Wyoming	20%	72.4	1978	Coal		Gillette, Wyoming		20%		72.4		1978
Neil Simpson CT	Gas	Gillette, Wyoming	100%	40.0	2000	Neil Simpson CT	Gas		Gillette, Wyoming		100%		40.0		2000
Lange CT	Gas	Rapid City, South Dakota	100%	40.0	2002	Lange CT	Gas		Rapid City, South Dakota		100%		40.0		2002
Ben French Diesel #1-5	Oil	Rapid City, South Dakota	100%	10.0	1965	Ben French Diesel #1-5	Oil		Rapid City, South Dakota		100%		10.0		1965
Ben French CTs #1-4	Gas/Oil	Rapid City, South Dakota	100%	80.0	1977-1979	Ben French CTs #1-4	Gas/Oil		Rapid City, South Dakota		100%		80.0		1977-1979
Wyoming Electric:						Wyoming Electric:
Cheyenne Prairie ^(c)	Gas	Cheyenne, Wyoming	42%	40.0	2014
Cheyenne Prairie						Cheyenne Prairie	Gas		Cheyenne, Wyoming		42%		40.0		2014
Cheyenne Prairie CT ^(c)	Gas	Cheyenne, Wyoming	100%	37.0	2014	Gas		Cheyenne, Wyoming		100%		37.0		2014
Corriedale (c)						Corriedale (c)	Wind		Cheyenne, Wyoming		38%		20.0		2020
Wygen II	Coal	Gillette, Wyoming	100%	95.0	2008	Wygen II	Coal		Gillette, Wyoming		100%		95.0		2008
Total MW Capacity				939.1		Total MW Capacity							991.6


~~(b)~~	The Peak View facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins. Peak View was placed in service in November 2016.


~~(c)~~	Cheyenne Prairie serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW).


~~(d)~~	Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our adjacent WRDC mine supplies all of the fuel for the plant.


~~(e)~~	Wyodak Plant, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by South Dakota Electric. This baseload plant is operated by PacifiCorp and our WRDC mine supplies all of the fuel for the plant.



Fuel Source (dollars per MWh)	2019		2018		2017
Coal	$	11.46	$	11.10	$	10.95

Natural Gas	$	25.92	$	33.42	$	34.05

Diesel Oil ^(a)	$	209.86	$	329.27	$	210.11

Total Weighted Average Fuel Cost	$	13.86	$	13.53	$	12.80

Purchased Power - Coal, Gas and Oil	$	43.73	$	45.62	$	45.63

Purchased Power - Renewable Sources	$	48.61	$	54.31	$	53.08


~~(a)~~	Included in the Price per MWh for Diesel Oil are unit start-up costs. The diesel-fueled generating units are generally used as supplemental peaking units and the cost per MWh is reflective of how often the units are started and how long the units are run.


Power Supply	2020		2019		2018
Coal	32.7	%	30.1	%	32.1	%
Natural Gas and Diesel Oil (a)	8.4		8.2		6.1
Wind	3.8		3.2		3.4
Total Generated	44.9		41.5		41.6
Coal, Natural Gas, Oil and Other Market Purchases	43.3		52.5		52.4
Wind	11.8		6.0		6.0
Total Purchased	55.1		58.5		58.4
Total	100.0	%	100.0	%	100.0	%


~~(a)~~	~~Wind represents approximately 6%, 6% and 6% of our purchased power in 2019, 2018, and 2017, respectively.~~


Fuel and Purchased Power (dollars per MWh)	2020		2019		2018
Coal	$	11.00	$	11.46	$	11.10
Natural Gas and Diesel Oil	21.67		28.26		34.07
Total Generated Weighted Average Fuel Cost	12.07		13.86		13.53
Coal, Natural Gas, Oil and Other Market Purchases	44.61		43.73		45.62
Wind Purchases	32.01		48.61		54.31
Total Purchased Power Weighted Average Cost	41.91		44.23		46.51��
Total Weighted Average Fuel and Purchased Power Cost	$	28.52	$	31.62	$	32.79


Utility	State	Transmission (a) (in Line Miles)	Distribution (in Line Miles)
Colorado Electric	Colorado	572	3,135
South Dakota Electric	South Dakota, Wyoming	1,242	2,565
Wyoming Electric	Wyoming	58	1,320
		1,872	7,020



Utility	State	Transmission (in Line Miles)	Distribution (in Line Miles)
Colorado Electric	Colorado	598	3,120
South Dakota Electric	South Dakota, Wyoming	1,219	2,557
South Dakota Electric - Jointly Owned ^(a)	South Dakota, Wyoming	43	—
Wyoming Electric	Wyoming	49	1,306
		1,909	6,983


◦	South Dakota Electric, Wyoming Electric, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity is charged for the use of assets located at the Gillette, Wyoming energy complex by the affiliate entity.


◦	South Dakota Electric and BHSC are parties to a shared facilities agreement, whereby BHSC is charged for the use of the Horizon Point facility that is owned by South Dakota Electric and BHSC provides certain operations and maintenance services at the facility.


◦	~~South Dakota Electric and Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.~~


~~(a)~~	Includes $121.3 million in 2019 rate base for the Common Use System formula rate that is updated annually and $17.1 million in rate base for the DC transmission tie that is based on the approved stated rate from 2005.


~~(a)~~	~~The combined degree days are calculated based on a weighted average of total customers by state.~~