BLACK HILLS CORP /SD/ (BKH) FY 2022 MD&A

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

Executive Summary

We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for more than 1.3 million customers and 800+ communities we serve. Our vision to be the Energy Partner of Choice directs our strategy to invest in the safety, sustainability and growth of our eight-state service territory, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming, and to meet our essential objective of providing safe, reliable and cost-effective electricity and natural gas.

We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We consider ourself a domestic electric and natural gas utility company.

We have provided energy and served customers for 139 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations.

A critical component of our strategy involves sustainable operations and supporting the Energy Transition. How we operate our company for the social good has never been more important. We are committed to cleaner energy and a low carbon future, integrating the Energy Transition and more renewable energy into our overall strategy and decision making. In addition, we are committed to a more sustainable future by better managing our impacts to the planet, whether that is water usage, recycling, biodiversity, or other important measures, and remaining focused on our human capital through diversity and inclusion.

Our emphasis is on consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operating efficiencies. These areas of focus will present the company with significant investment needs as we harden our infrastructure systems, meet customer growth and fulfill customer expectations for cleaner energy services. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective solutions.

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Key Elements of our Business Strategy

Modernize and operate utility infrastructure to provide customers with safe, reliable, cost-effective electric and natural gas service. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that spans nearly 1,600 miles. Our Electric Utilities own and operate 1,482 MW of generation capacity and 9,024 miles of transmission and distribution lines and our Gas Utilities own and operate approximately 47,000 miles of natural gas transmission and distribution pipelines.

A key strategic focus is to modernize and harden our utility infrastructure to meet customers’ and communities’ varied energy needs, ensure the continued delivery of safe, reliable and cost-effective energy and reduce GHG emissions intensity. In addition, we invest in the expansion, capacity and integrity of our systems to meet customer growth.

We rigorously comply with all applicable federal, state and local regulations and strive to consistently meet industry best practice standards. A key component of our modernization effort is the development of programs by our Electric and Gas Utilities to systematically and proactively replace aging infrastructure on a system-wide basis.

To meet our electric customers’ continued expectations of high levels of reliability, a key strength of the Company, our Electric Utilities utilize an integrity program to ensure the timely repair and replacement of aging infrastructure. In alignment with this program, in November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The 260-mile, multi-phase transmission expansion project will provide customers long-term price stability and greater flexibility as power markets develop in the Western States. On October 11, 2022, the WPSC approved a CPCN submitted by Wyoming Electric to construct the transmission expansion project. Construction of the project is expected to take place in multiple phases or segments from 2023 through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems.

Our Gas Utilities utilize a programmatic approach to system-wide pipeline replacement, particularly in high consequence areas. Under the programmatic approach, obsolete, at-risk and vintage materials are replaced in a proactive and systematic time frame. We have removed all cast- and wrought-iron from our natural gas transmission and distribution systems and continue to replace aging infrastructure through programs that prioritize safety and reliability for our customers. Our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments, between rate reviews, which allow timely recovery of costs incurred in repairing and replacing the gas delivery systems with a return on the investment.

As of December 31, 2022, we estimate our five-year capital investment to be approximately $3.5 billion, with most of that investment targeted toward upgrading existing utility infrastructure supporting customer and community growth needs, and complying with safety requirements. Our actual 2022 and forecasted capital expenditures for the next five years from 2023 through 2027 are as follows (in millions). Minor differences may result due to rounding.

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

(b)
These represent projects that are being evaluated by our segments for timing, cost and other factors.

Efficiently plan, construct and operate power generation facilities to serve our Electric Utilities. We best serve customers and communities when generation is vertically integrated into our Electric Utilities. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to supply cost-effective electricity to our customers. These generation assets can be rate-based or non-regulated assets within our Electric Utilities segment. However, we believe that generation assets that are rate-based provide long-term benefits to customers.

Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs (operations located near energy hubs), efficiency in converting fuel into energy and low per unit operating and maintenance costs. In addition, we operate our plants with high levels of Availability as compared to industry benchmarks.

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Rate Base Generation: We continue to believe that customers are best served when the power generation facilities are owned and rate-based by our Electric Utilities. Rate-based generation assets offer several advantages for customers and shareholders, including:

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

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

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

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

Integrated Generation: Our Electric Utilities segment also includes a power generation business that owns non-regulated generating facilities that are contracted through long-term power purchase agreements with our electric utilities. Our power generation business has an experienced staff with significant expertise in planning, building and operating power plants. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the Company’s generation assets. Our power generation business competitively bids for energy and capacity through requests for proposals by our Electric Utilities for energy resources necessary to serve customers. This business can bid competitively due to construction expertise, fuel supply advantages and by co-locating new plants at our existing Electric Utilities’ energy complexes, reducing infrastructure and operating costs. All power plants within this business, except Northern Iowa Windpower, are contracted to our Electric Utilities under long-term contracts and are located at our utility-generating complexes, including Busch Ranch, Pueblo Airport Generation, and the Gillette, Wyoming energy complex, and are physically integrated into our Electric Utilities’ operations.

Generation Fuel Supply: Our generating facilities are strategically located close to energy hubs that help reduce fuel supply costs. Our Colorado and Wyoming gas-fired generating facilities are located close to major natural gas energy hubs that provide trading liquidity and transparent pricing. Due to their location in the resource rich areas of Colorado and Wyoming, natural gas supply to fuel our gas-fired generation can be sourced at competitive prices. Our coal-fired power plants, all located at the Gillette energy complex in northeastern Wyoming, are supplied by our adjacent coal mine. We operate and own majority interests in four of the five power plants and own 20% of the fifth power plant. Our coal mine provides approximately 3.7 million tons of low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.09 per MMBtu for year ended December 31, 2022) when compared to alternatives. Nearly all the mine’s production is sold to these on-site generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck.

Supporting the Energy Transition by proactively integrating alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities by 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are compared to a 2005 baseline. Electric Utility goals include Scope 1 emissions from electric utility generating units and Scope 3 emissions from purchased power for sales. Our Gas Utilities goal includes Scope 1 emissions from distribution system main and service lines. On August 31, 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubles the previous target of a 50% reduction by 2035 and expands the scope of the goal to all Scope 1 sources of methane emissions on our distribution system. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-party damage reduction, expanding the use of RNG and hydrogen, and utilizing carbon credit offsets.

Since 2005, we have reduced GHG emissions intensity from our Gas Utilities distribution system mains and services by more than 33% and achieved a one-third reduction from our Electric Utilities (a nearly 10% reduction since announcing our goal in 2020 for our Electric Utilities). We have plans in place today, without reliance on future technologies, to achieve our corporate climate goals calling for a 40% reduction in greenhouse gas emissions intensity from our electric utility operations by 2030 and 70% by 2040. Additionally, our Electric Utilities have reduced nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Colorado Electric has achieved a nearly 50% reduction in GHG emissions since 2005 and is on track to reach the State of Colorado’s 80% carbon reduction goal by 2030. Our goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This keeps our customers at the forefront of our decision-making, which is central to our values.

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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 Electric and Wyoming Electric customers. In support of this program, we created and received approvals for new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmental customer requests for renewable energy resources. To meet the renewable energy commitments under the new tariffs, in November 2020, we completed construction and placed into service the Corriedale wind project, a 52.5 MW wind energy project near Cheyenne, Wyoming.

•
In June 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. The IRP outlines a range of options for the two electric utilities over a 20-year planning horizon to meet long-term forecasted energy needs while strengthening reliability and resiliency of the grid. The analysis focused on the least-cost resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving the Company’s generation emissions reduction goals. The IRP’s preferred options for South Dakota Electric in the near-term planning period through 2026 are the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 10 MW of battery storage.

•
On January 13, 2023, Colorado Electric submitted a unanimous settlement for its Clean Energy Plan filed May 25, 2022, with the CPUC. If approved, the plan would add approximately 400 MW of new clean energy resources needed to reduce carbon emissions 80% by 2030. A final decision from the CPUC is expected in the first quarter of 2023.

Many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting GHG emission reduction targets. Federal legislation for renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely drive the need for significant investment in our Electric Utilities and Gas Utilities segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility, we are responsible for providing safe, reliable and cost-effective sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with standards and regulations that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.

Inflation Reduction Act

The IRA, signed into law by President Biden on August 16, 2022, features $370 billion in spending and tax incentives on clean energy provisions. Most notably, the IRA includes provisions that extend and expand the production and investment tax credits for wind and solar; include energy storage, EVs, RNG, and carbon capture and sequestration; and allow for the transferability of clean energy tax credits on existing and qualifying new facilities. We see the IRA as generally supportive of our Energy Transition strategy and as having the potential to drive increased value for our customers and shareholders. We are still evaluating the impacts of the IRA provisions on our future capital projects.

Explore opportunities as an energy solutions provider. Another strategic initiative is to grow our business through creative energy solutions with new customers and partnerships. We see value creation by recruiting new customers and expanding existing partnerships with data centers and blockchain opportunities; exploring energy markets such as RTOs; and expanding our transmission capabilities. A few recent examples of our initiatives to grow our business through creative solutions include:

•
In 2022, Wyoming Electric entered into two new PPAs with third parties to purchase up to 106 MW of wind energy and up to 150 MW of solar energy, upon construction of new renewable generation facilities (to be owned by third parties) which are expected to be completed by the end of 2023. The renewable energy from these PPAs will be used to serve our expanding partnerships with data centers.

•
We have supported enabling legislation in Wyoming for the growing blockchain businesses while implementing our own BCIS Tariff to serve these customers. In June 2022, Wyoming Electric completed its first agreement, a five-year agreement to deliver up to 45 MW with an option to expand service up to 75 MW to a new customer in Cheyenne, Wyoming, under this Tariff. Energy will be sourced through the electric energy market and delivered through our Electric Utilities’ infrastructure. Under the agreement, the customer will be responsible for costs of service, and the load will be interruptible to prioritize the needs of Wyoming Electric’s existing retail customers.

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•
During the first quarter of 2022, Colorado Electric agreed to join SPP’s WEIS Market. On September 26, 2022, South Dakota Electric and Wyoming Electric also agreed to join the WEIS Market. South Dakota Electric and Wyoming Electric will join Colorado Electric in integrating into the WEIS Market in April 2023 and expects to continue studying long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market.

Additionally, we are pursuing two important initiatives in the form of sustainable energy solutions for electric vehicles and RNG. These two programs support our near-term sustainable strategy and contribute to the achievement of our aspirational greenhouse gas emissions reduction goals.

•
Electric Vehicles: We expect EV market share to increase over the next one to three years, commensurate with a significant uptick in vehicle range and product offerings and marked decrease in EV purchase prices. In addition to future load growth opportunities, we are investigating behind-the-meter solutions for customers. In January 2022, the CPUC approved a transportation electrification plan for Colorado Electric including the implementation of EV and charger rebates and EV rates.

•
Renewable Natural Gas: In 2021, we developed a voluntary RNG and carbon offset program to help our residential and small business natural gas customers offset up to 100% or more of the emissions associated with their own natural gas usage. In 2022, we filed for approval to launch these programs in three of our states, receiving regulatory approval for the program from both the KCC and the NPSC in Q4 2022. We intend to begin offering the program to customers in 2023, as well as completing additional regulatory filings with commissions in our other natural gas states.

Our teams are also evaluating multiple RNG investment opportunities and exploring value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with six projects actively injecting RNG into our natural gas system. In 2022, we created a new non-regulated business, BHERR, which will drive new growth by investing capital into infrastructure assets that provide a pathway for RNG to enter the market. BHERR builds on our expertise and experience in both RNG and natural gas asset operations, and aligns with market demand and the path to a cleaner energy future.

Execute disciplined capital allocation and explore small strategic opportunities. We are planning a disciplined capital investment program of approximately $600 million during the next year to improve our cash flows and reduce our debt to total capitalization ratio. By carefully managing capital, we plan to continue to strengthen our balance sheet and enhance our liquidity. With this goal in mind, we will continue to evaluate smaller scale acquisitions of private utility infrastructure systems and small municipal systems that can be easily incorporated into our existing utility systems.

Deliver a competitive total return to investors and maintain an investment grade credit rating. We are proud of our track record of annual dividend increases for shareholders. 2022 represented our 52nd consecutive year of increasing dividends. In January 2023, our Board of Directors declared a quarterly dividend of $0.625 per share, equivalent to an annual dividend of $2.50 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 55% to 65% of net income.

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

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Recent Developments

Macroeconomic Trends

We are monitoring adverse macroeconomic trends including potential recession, inflationary pressures on the prices of commodities, materials, outside services and employee costs; supply chain constraints; rising interest rates and a competitive and tight labor market. To date, we have experienced moderate net impacts from these trends. However, if current macroeconomic conditions continue or deteriorate in 2023, adverse impacts to our businesses may be magnified.

Higher commodity energy costs continue to have an effect on customer bills and deferred energy costs. Our utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer, which mitigates our exposure. Customer billing rates are adjusted periodically to reflect changes in our cost of energy. As a result of increased customer billings, we incurred higher bad debt expense.

Higher deferred energy costs and rising interest rates have led to increased interest expense and increased short-term variable rate borrowings, which include our Revolving Credit Facility and CP Program. However, the increased interest expense for the year ended December 31, 2022 was limited since 88% of our debt at December 31, 2022, is fixed rate debt. Rising discount rates and recent capital markets volatility had a limited impact to the unfunded status of the BHC Pension Plan when compared to the prior year.

We are proactively managing increased costs of materials and supply chain disruptions to achieve our forecasted capital investment targets. To support our 2023 capital investment program, we have contracted materials for the majority of our largest forecasted projects. We continue to forecast multi-year key material requirements with suppliers to enhance predictable material availability, challenge vendor price increases to ensure best value and cost transparency and invest in our distribution network to ensure the safety and continuity of our system. We have also evaluated each of our forecasted projects and will prioritize depending on future constraints. Project delays may occur if costs rise significantly or if materials are not available.

Inflationary pressures and supply chain constraints have increased our operating expenses, which included higher outside services expenses (i.e., consulting and contractor rates), materials expenses and vehicle expenses driven by higher fuel prices.

We are faced with increased competition for employee and contractor talent in the current labor market. To date, we have seen a limited net increase in total employee costs due to increased employee and contractor costs related to attraction and retention of talent mostly offset by workforce attrition.

More detailed discussion of the future uncertainties can be found in Item 1A - Risk Factors.

Business Segment Highlights and Corporate Activity

Electric Utilities

•
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate review activity for Wyoming Electric.

•
See Key Elements of our Business Strategy section above for discussion of recent developments related to Ready Wyoming, Wyoming Electric's BCIS tariff, Colorado Electric's Clean Energy Plan filing, and the Electric Utilities joining the WEIS Market.

•
In December 2022, each of our Electric Utilities set new winter peak loads:

•
On December 22, 2022, Colorado Electric set a new winter peak load of 334 MW, surpassing the previous winter peak of 313 MW set in October 2018.

•
On December 21, 2022, South Dakota Electric set a new winter peak load of 355 MW, surpassing the previous winter peaks of 327 MW set on January 5, 2022 and 326 MW set in February 2021.

•
On December 21, 2022, Wyoming Electric set a new winter peak load of 281 MW, surpassing the previous peaks of 263 MW set on November 17, 2022, 262 MW set on February 23, 2022, 252 MW set on January 5, 2022 and 247 MW set in December 2019.

•
In December 2022, WRDC entered into a new agreement with PacifiCorp, effective January 1, 2023, to continue as the sole supplier of coal (fuel) to the Wyodak Plant through December 31, 2026 with a one-year extension option to December 31, 2027. Pricing and other terms of the new fuel supply agreement are similar to the previous contract which ended December 31, 2022.

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•
In July 2022, South Dakota Electric and Wyoming Electric both set new all-time and summer peak loads:

•
On July 21, 2022, Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous peaks of 288 MW set on July 18, 2022, 282 MW set on June 13, 2022 and 274 MW set in July 2021.

•
On July 18, 2022, South Dakota Electric set a new all-time and summer peak load of 403 MW, surpassing the previous summer peak of 397 MW set in July 2021.

Gas Utilities

•
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate review activity for Arkansas Gas and RMNG.

•
See Key Elements of our Business Strategy section above for discussion of recent developments related to our Gas Utilities' voluntary RNG and carbon offset programs.

Corporate and Other

•
On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3-million-acre concession award in Costa Rica that was acquired by a BHC subsidiary in 2003. We believe we have meritorious defenses to the verdict and have appealed the verdict. See additional information in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

Results of Operations

Our discussion and analysis for the year ended December 31, 2022 compared to 2021 is included herein. For discussion and analysis for the year ended December 31, 2021 compared to 2020, 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, 2021, which was filed with the SEC on February 15, 2022.

Segment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.

Consolidated Summary and Overview

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2022 Compared to 2021

The variance to the prior year included the following:

•
Electric Utilities’ operating income increased $12 million primarily due to increased rider revenues, prior year impacts related to the Wygen I unplanned outage and Colorado Electric’s TCJA-related bill credits to customers, increased transmission services revenue and off-system excess energy sales partially offset by higher operating expenses and lower pricing on the new Wygen I PPA;

•
Gas Utilities’ operating income increased $33 million primarily due to new rates and rider recovery, favorable weather, carrying costs on our Winter Storm Uri regulatory asset, prior year Black Hills Energy Services Winter Storm Uri costs, customer growth partially offset by higher operating expenses;

•
Corporate and Other expenses decreased $1.2 million primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments;

•
Interest expense increased $8.6 million due to higher interest rates on higher short-term debt balances;

•
Income tax expense increased $18 million driven by higher pre-tax income and a higher effective tax rate primarily due to prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits and decreased flow-through tax benefits driven by prior year repairs and gain deferral partially offset by tax benefits from various state tax rate changes; and

•
Net income attributable to non-controlling interest decreased $2.1 million due to lower net income from Black Hills Colorado IPP primarily driven by lower fired-engine hours and a planned outage.

Segment Operating Results

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Electric and Gas Utility margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Electric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses, depreciation and amortization expenses, and property and production taxes from the measure.

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

Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

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Electric Utilities

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

2022 Compared to 2021

Electric Utility margin increased over the prior year as a result of:

(a)
In February 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income.

(b)
Primarily driven by favorable market pricing on contracts and off-system sales.

Operations and maintenance expense increased due to $10.3 million of higher generation-related expenses primarily due to higher fuel and materials costs and increased royalties on higher mining revenues, $4.5 million of higher outside services expenses primarily driven by higher contractor and consultant rates, $3.4 million of increased property taxes due to an expiration of an abatement and a higher asset base driven by recent capital expenditures, $3.4 million of higher cloud computing licensing costs, and $1.1 million of increased bad debt expense primarily attributable to higher customer billings.

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

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Operating Statistics

(a)
Primarily related to transmission revenues from the Common Use System.

(b)
Includes Integrated Generation and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.

(c)
Includes company uses and line losses.

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(a)
Degree days are calculated based on a weighted average of total customers by state.

(a)
Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.

(b)
2021 included planned outages at Neil Simpson II, Wygen II, and Wygen III and unplanned outages at Wygen I, Neil Simpson II and Wyodak Plant.

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Gas Utilities

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

2022 Compared to 2021

Gas Utility margin increased over the prior year as a result of:

(a)
In certain jurisdictions, we have commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. Additionally, the carrying costs accrued during the year ended December 31, 2022 included a one-time, $10.3 million true-up to reflect commission authorized rates. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

(b)
Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri was not recoverable through a regulatory mechanism.

Operations and maintenance expense increased due to $11.6 million of higher outside services and materials expenses driven primarily by higher contractor and consultant fees, $5.0 million of increased bad debt expense primarily attributable to higher customer billings, $4.6 million of higher cloud computing licensing costs, $3.2 million of higher property taxes driven by a higher asset base on recent capital expenditures, $2.1 million of higher vehicle expense driven by higher fuel costs, $1.6 million of higher employee-related expenses and $1.2 million increased travel and training 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

(a)
Includes Black Hills Energy Services and non-regulated services under the Service Guard Comfort Plan, Tech Services and HomeServe.

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

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

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Corporate and Other

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

2022 Compared to 2021

The variance in Operating income (loss) was primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments.

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

2022 Compared to 2021

Interest expense, net

The increase in Interest expense, net was due to higher interest rates on higher short-term debt balances. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

Other income (expense), net

Other income (expense), net was comparable to the prior year primarily due to lower costs for our non-qualified benefit plans which were driven by market performance mostly offset by a prior year recognition of death benefits from Company-owned life insurance and higher non-service pension costs primarily driven by a higher discount rate.

Income tax benefit (expense)

Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the year ended December 31, 2022, the effective tax rate was 8.5% compared to 2.8% in 2021. The higher effective tax rate was primarily due to $10 million of prior year tax benefits from Colorado Electric TCJA-related bill credits to customers (which were offset by reduced revenue) and $5.4 million decreased flow-through tax benefits driven by prior year repairs and gain deferral partially offset by $4.0 million of current year tax benefits from various state rate changes, and $1.8 million of increased tax benefits from federal PTCs driven by a current year PTC rate increase (inflation adjustment). See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

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Liquidity and Capital Resources

OVERVIEW

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

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

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

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

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

(b)
Long-term debt as a percentage of long-term debt and stockholders' equity combined.

(c)
Total debt (notes payable, current maturities of long-term debt and long-term debt) as a percentage of total debt and stockholders' equity combined.

CASH FLOW ACTIVITIES

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

Operating Activities:

2022 Compared to 2021

Cash earnings (income from continuing operations plus non-cash adjustments) were $39 million higher than prior year primarily due to increased Electric and Gas Utility margins due to new rates and rider revenues and prior year impacts from Winter Storm Uri.

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Net inflows from changes in certain operating assets and liabilities were $626 million higher than prior year, primarily attributable to:

•
Cash inflows increased by approximately $728 million primarily as a result of changes in our regulatory assets and liabilities primarily driven by prior year incremental fuel, purchased power and natural gas costs due to Winter Storm Uri and current year recovery of a portion of Winter Storm Uri incremental and carrying costs from customers;

•
Cash outflows increased by approximately $181 million primarily as a result of changes in accounts receivable and other current assets driven by increased revenue due to higher commodity prices and colder weather and increased purchases of natural gas in storage;

•
Cash inflows increased by approximately $79 million as a result of changes in accounts payable and other current liabilities driven by payment timing related to natural gas and power purchases and other working capital requirements;

Cash outflows increased $15.2 million from other operating activities primarily due to higher cloud computing licensing costs, increased payments on settled commodity derivatives and higher preliminary survey charges.

Investing Activities:

2022 Compared to 2021

Capital expenditures of approximately $604 million in 2022 compared to $677 million in 2021. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas and Electric Utilities; and

Cash inflows decreased $13 million for other investing activities which was primarily driven by prior year sales of transmission assets and facilities, none of which were individually material.

Financing Activities:

2022 Compared to 2021

Net cash provided by financing activities decreased $700 million primarily due to prior year financing activities related to Winter Storm Uri.

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CAPITAL RESOURCES

Short-term Debt

Revolving Credit Facility and CP Program

We have a $750 million Revolving Credit Facility that matures on July 19, 2026, with two one-year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment. We also have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million.

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.

See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our Revolving Credit Facility and CP Program.

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 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

For information on our long-term debt, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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, 2022. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Equity

Shelf Registration

We have a shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2023. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2022, we had approximately 66 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.

For additional information regarding equity, see Note 8 of the 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 strategic objectives. We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, the issuance of common stock under our ATM program or in an opportunistic block trade. In the first quarter of 2023, we plan to re-finance a portion of our short-term borrowings into long-term debt. We also plan to re-finance our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date. Additionally, we plan to renew our ATM and shelf registration at or before shelf expiration in August 2023.

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, 2022:

(a)
On August 26, 2022, S&P reported BBB+ rating and maintained a Stable outlook.

(b)
On December 20, 2022, Moody's reported our Baa2 rating and maintained a Stable outlook.

(c)
On October 6, 2022, 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, 2022:

(a)
On March 31, 2022, S&P reported A rating.

(b)
On October 6, 2022, Fitch reported A rating.

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

CAPITAL REQUIREMENTS

Capital Expenditures

Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity of our system and is included in utility rate base and eligible for recovery from our utility customers with regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.

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Our historical capital expenditures by reportable segment are shown in Note 16 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Repayments of Indebtedness

For information relating to repayments of our short- and long-term debt and associated interest payments, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Unconditional Purchase Obligations

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

Defined Benefit Pension Plan

We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The unfunded status of the Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the Pension Plan is $35 million as of December 31, 2022, compared to $20 million as of December 31, 2021. The increase in the unfunded status of the Pension Plan was primarily driven by an increase in the discount rate. We do not have required contributions and we do not expect to make contributions to our Pension Plan in 2023. See further information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Common Stock Dividends

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

Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

On January 25, 2023, our Board of Directors declared a quarterly dividend of $0.625 per share, equivalent to an annual dividend rate of $2.50 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:

Our three-year compound annualized dividend growth rate was 5.5%.

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, 2022, 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, 2022 was not material. See Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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.

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Critical Accounting Estimates

We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. We continue to closely monitor the macroeconomic environment and related impacts on our critical accounting estimates including, but not limited to, collectability of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, and contingent liabilities. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.

The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Regulation

Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.

Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state regulatory commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs.

As of December 31, 2022 and 2021, we had total regulatory assets of $653 million and $797 million, respectively, and total regulatory liabilities of $519 million and $503 million, respectively. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

Goodwill

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns with our financial planning process.

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

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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 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 6.9% to 7.0% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2022. Although 1.75% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews. Under the market approach, we estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.

At October 1, 2022, fair value exceeded the carrying value at all reporting units. However, the Gas Utilities reporting unit’s fair value exceeded its carrying value by less than 10% and could be at risk for impairment if adverse macroeconomic conditions persist or deteriorate. The decrease in the fair value cushion of the Gas Utilities reporting unit when compared to the prior year was primarily due to an increase in the weighted average cost of capital.

The estimates and assumptions used in our 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, 2022, 2021, and 2020, there were no impairment losses recorded. At December 31, 2022, the fair value exceeded the carrying value at all reporting units.

See Item 1A - Risk Factors and Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be made in the period such determination was made. These adjustments may increase or decrease earnings. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.

See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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