BKH US Equity☆

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 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 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.

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.

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 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

(in millions)

____________________________

(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 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 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 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 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.

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

Vertically integrate businesses that are supportive of our Electric and Gas Utility businesses. While our primary focus is 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 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 portion of this term loan prior to maturity and refinance the 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 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 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 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 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 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 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 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 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 annual revenue decrease of $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 on August 2, 2019 for approval of a new 60 MW PPA. See additional information in the Electric Utilities Segment highlights above.

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,

(in thousands)

Adjusted operating income (a) :

(Loss) from discontinued operations, net of tax — — (6,887)

Net income attributable to noncontrolling interest (15,155) (14,012) (14,220)

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

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(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 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)

________________

(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:

Purchased:

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For the year ended December 31,

Generated:

Purchased:

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(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,

Heating Degree Days:

Cooling Degree Days:

________________

(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

Natural gas and diesel oil (b) 80.6% 87.9% 96.4%

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(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):

Revenue:

Cost of natural gas sold:

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)

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

For the year ended December 31,

________________

(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 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)

____________________

(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:

Purchased:

____________________

(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

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 Compared to 2019

Adjusted operating income was comparable to the prior year.

Operating Statistics

Corporate and Other

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

2020 Compared to 2019

The variance in Adjusted operating income (loss) was primarily due to lower unallocated employee costs.

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

2020 Compared to 2019

Interest Expense

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

Impairment of Investment

In the current year, we recorded a pre-tax non-cash write-down of $6.9 million in our investment in equity securities of a privately held oil and gas company, compared to a $20 million write-down in the prior year. The impairments in both years were triggered by continued adverse natural gas prices and liquidity concerns at the privately held oil and gas company. The remaining book value of our investment is $1.5 million, and this is our only remaining investment in oil and gas 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)

The variance in Other income (expense), net was due to the prior year expensing of $5.4 million of development costs related to projects we no longer intend to 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 lower effective tax rate is primarily due to increased tax benefits from federal production tax credits associated with new wind assets and one-time research and development tax credits partially offset by a prior year tax benefit from a federal tax loss carry-back claim including interest. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

Liquidity and Capital Resources

OVERVIEW

Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our operating activities, five-year Revolving Credit Facility, CP Program, ATM and ability to access the public and private capital markets through debt and equity securities offerings when necessary. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.

We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices, as well as during the construction season which typically peaks in spring and summer.

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.

In response to 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.

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

Cash and cash equivalents $ 6,356 $ 9,777

Restricted cash and equivalents $ 4,383 $ 3,881

Current maturities of long-term debt $ 8,436 $ 5,743

Ratios

Long-term debt ratio 58 % 57 %

Total debt ratio 60 % 60 %

______________

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

CASH FLOW ACTIVITIES

The following table summarizes our cash flows for the years ended December 31 (in thousands):

Cash provided by (used in)

2020 Compared to 2019

Operating Activities:

Net cash provided by operating activities was $36 million higher than in 2019. The variance to the 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 Gas Utilities;

•Net inflows from changes in certain operating assets and liabilities were $18 million higher than prior year, primarily attributable to:

•Cash inflows decreased by approximately $18 million primarily as a result of 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 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 customers in the prior year.

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

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Investing Activities:

Net cash used in investing activities was $55 million lower than in 2019. This variance to the 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 Natural Bridge pipeline project, the Busch Ranch II wind project and construction of the final segment of 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 in excess of issuances;

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

•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.

CAPITAL SOURCES

Revolving Credit Facility and CP Program

We have a $750 million Revolving Credit Facility that matures on July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility 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. 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.

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

The Revolving Credit Facility contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to 1) make timely payments of debt obligations; or 2) triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permit the acceleration of debt maturities or mandatory debt prepayment.

Our Revolving Credit Facility and CP Program had the following borrowings, outstanding letters of credit, and available capacity (in millions):

Current Short-term borrowings at Letters of Credit (a) at Available Capacity at

__________

(a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit. For more information on these letters of credit, see Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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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 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. 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

__________

(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, 2020.

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 a shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2023. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2020, we had approximately 63 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 2020, we did not issue any shares of common stock under the ATM.

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

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Future Financing Plans

We will continue to assess debt and equity needs to support our capital investment plans and other key strategic objectives. In 2021, we expect to fund our capital plan and strategic objectives by using cash generated from operating activities, our Revolving Credit Facility and CP Program, and issuing $100 million to $120 million of common stock under the ATM. As discussed in the 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 portion of this term loan prior to maturity and refinance the remaining portion in longer-term debt.

CREDIT RATINGS

Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. We note that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2020:

Rating Agency Senior Unsecured Rating Outlook

S&P (a) BBB+ Stable

Moody’s (b) Baa2 Stable

Fitch (c) BBB+ Stable

__________

(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.

(c) On August 20, 2020, Fitch reported BBB+ rating and maintained a Stable outlook.

Certain fees and interest rates under our Revolving Credit Facility are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgrades our senior unsecured debt, we will be required to pay higher fees and interest rates under our Revolving Credit Facility.

The following table represents the credit ratings of South Dakota Electric at December 31, 2020:

Rating Agency Senior Secured Rating

S&P (a) A

Moody’s (b) A1

Fitch (c) A

__________

(a) On April 16, 2020, S&P reported A rating.

(b) On December 21, 2020, Moody’s reported A1 rating.

(c) On August 20, 2020, Fitch reported A rating.

We do not have any trigger events (i.e., an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.

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CAPITAL REQUIREMENTS

Capital Expenditures

Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity 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):

Capital Expenditures By Segment (a) :

Discontinued operations — — 2,402

____________________________

(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.

Unconditional Purchase Obligations

We have unconditional purchase obligations which include the energy and capacity costs associated with our PPAs, transmission services agreements, and natural gas capacity, transportation and storage agreements. Additionally, our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. For additional information. see Note 3 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Defined Benefit Pension Plan

We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The unfunded status of the Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the plan is $40 million as of December 31, 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

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated and approved by our Board of Directors.

Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 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:

Dividend Payout Ratio 60 % 63% 40%

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 may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty. At December 31, 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 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 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Critical Accounting Policies Involving Significant 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 Description and Significant Accounting Policies” of our Notes to 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 regulatory commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs.

As of December 31, 2020 and 2019, we had total regulatory assets of $278 million and $271 million, respectively, and total regulatory liabilities of $533 million and $537 million, respectively. See Note 2 of the Notes to 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 with our financial planning process.

Accounting standards for testing goodwill for impairment require the application of either a qualitative or quantitative assessment to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. Under either the qualitative or quantitative assessment, the estimated fair value of a reporting unit is compared with its carrying amount, including goodwill. If the carrying amount exceeds fair value, then an impairment loss would be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit.

Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which the Chief Operating Decision Maker (CODM) regularly reviews the operating results. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industries. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the range of 5% to 6% and long-term growth rate projections in the 1% to 2% range were utilized in the goodwill impairment test performed as of 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. 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, and 2018, there were no impairment losses recorded. At December 31, 2020, the fair value substantially exceeded the carrying value at all reporting units.

As described in Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, we adopted ASU 2017-04, Simplifying the Test for Goodwill Impairment, prospectively on January 1, 2020.

Pension and Other Postretirement Benefits

As described in Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, we have one defined benefit pension plan, one defined post-retirement healthcare plan and several non-qualified retirement plans. A Master Trust holds the assets for the pension plan. A VEBA trust for the funded portion of the post-retirement healthcare plan has also been established.

Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rates, healthcare cost trend rates, expected return on plan assets, compensation increases, retirement rates and mortality rates. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions determined by management and used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.

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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 2021 pension benefit cost for our non-contributory funded pension plan is expected to be $0.5 million compared to $4 million in 2020. The decrease in the expected 2021 pension benefit cost is driven primarily by favorable asset returns partially offset by a decrease in the discount rate.

The effect of hypothetical changes to selected assumptions on the pension and other postretirement benefit plans would be as follows in thousands of dollars:

December 31,

Pension

Expected return on assets +/- 0.5 N/A (2,367)/2,372

OPEB

Expected return on assets +/- 0.5 N/A (38)/38

__________________________

(a) Projected benefit obligation (PBO) for the pension plan and accumulated postretirement benefit obligation (APBO) for OPEB plans.

(b) Impact on service cost, interest cost and amortization of gains or losses.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. 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, 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, 2020, the Company has amortized $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 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 17 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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New Accounting Pronouncements

See Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2020 or pending adoption.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.

Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed, but not limited to, the following market risks:

•Commodity price risk associated with our retail natural gas services, wholesale electric power marketing activities and fuel procurement for several of our gas-fired generation assets. Market fluctuations may occur due to unpredictable factors such as the 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 2008 financial crisis and the COVID-19 pandemic.

Credit risk is associated with financial loss resulting from non-performance of contractual obligations by a counterparty.

To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at least quarterly and as necessary, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.

Commodity Price Risk

Electric and Gas Utilities

Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to reflect billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota and Wyoming, we have ECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that adjust natural gas rates when our natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic prudence reviews by the state regulatory commissions.

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state regulatory commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations.

For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income. See additional information in Note 11 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Wholesale Power

We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments and do not 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 power that exceeds our generating capacity. These potential short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin.

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Black Hills Energy Services

We buy and sell natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with fixed price forward contracts to supply gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings.

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, 2020, we had no interest rate swaps in place. Further details of past swap agreements are set forth in Note 11 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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 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 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Credit Risk

We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses and any specific customer collection issue that is identified. Our credit exposure at December 31, 2020 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.

See more information in Notes 1 and 11 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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, 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, 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, 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") as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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, 2020, 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 26, 2021, 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 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).

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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.

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) 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 Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 26, 2021

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per share amounts)

Operating expenses:

Other operating expenses — — 1,841

Other income (expense):

Net (loss) from discontinued operations — — (6,887)

Net income attributable to noncontrolling interest (15,155) (14,012) (14,220)

Amounts attributable to common shareholders:

Net (loss) from discontinued operations — — (6,887)

Earnings (loss) per share of common stock, Basic -

Earnings from continuing operations $ 3.65 $ 3.29 $ 4.88

(Loss) from discontinued operations — — (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 — — (0.12)

Total earnings per share of common stock, Diluted $ 3.65 $ 3.28 $ 4.66

Weighted average common shares outstanding:

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

Other comprehensive income (loss), net of tax:

Derivative instruments designated as cash flow hedges:

Other comprehensive income (loss), net of tax 3,309 (3,739) 7,027

See Note 13 for additional disclosures related to Comprehensive Income.

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

As of

(in thousands)

ASSETS

Current assets:

Cash and cash equivalents $ 6,356 $ 9,777

Restricted cash and equivalents 4,383 3,881

Derivative assets, current 1,848 342

Other assets:

The accompanying Notes to 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

(in thousands, except share amounts)

LIABILITIES AND EQUITY

Current liabilities:

Derivative liabilities, current 2,044 2,254

Current maturities of long-term debt 8,436 5,743

Deferred credits and other liabilities:

Commitments, contingencies and guarantees (Note 3)

Equity:

Stockholders’ equity -

Accumulated other comprehensive income (loss) (27,346) (30,655)

The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

Operating activities:

Loss from discontinued operations, net of tax — — 6,887

Change in certain operating assets and liabilities:

Investing activities:

Purchase of investment — — (24,429)

Net cash provided by investing activities of discontinued operations — — 20,385

Financing activities:

Net change in cash, restricted cash and cash equivalents (2,919) (10,487) 5,905

Supplemental cash flow information:

Cash (paid) refunded during the period for continuing operations:

Non-cash investing and financing activities from continuing operations:

The accompanying Notes to 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

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)

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)

Other comprehensive income (loss), net of tax — — — — — — (3,739) — (3,739)

Dividends on common stock ($2.05 per share) — — — — — (124,647) — — (124,647)

Issuance costs — — — — (1,182) — — — (1,182)

Distributions to noncontrolling interest — — — — — — — (17,901) (17,901)

Other comprehensive income (loss), net of tax — — — — — — 3,309 — 3,309

Dividends on common stock ($2.17 per share) — — — — — (135,439) — — (135,439)

Issuance costs — — — — (1,203) — — — (1,203)

Distributions to noncontrolling interest — — — — — — — (15,839) (15,839)

The accompanyingNotes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

Notes to Consolidated Financial Statements

December 31, 2020, 2019 and 2018

(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