BLACK HILLS CORP /SD/ - Annual Report: 2019 (Form 10-K)

---

---

---

---

---

---

---

---

ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

(a)	The Colorado Electric July 2019 summer peak load of 422 surpassed previous summer peak record load of 413 set in June 2018. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011.

(b)	The Wyoming Electric July 2019 summer peak load of 265 surpassed previous summer peak record load of 254 set in July 2018. The December 2019 winter peak load of 247 surpassed the previous winter peak record load of 238 set in December 2018.

---

(a)	Busch Ranch I is operated by Colorado Electric. In 2013, the facility was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act. Black Hills Electric Generation owns the remaining 50% interest in the wind farm. Colorado Electric has a PPA with Black Hills Electric Generation for its share of power from the wind farm.

(b)	The Peak View facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins. Peak View was placed in service in November 2016.

(c)	Cheyenne Prairie serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 95 MW unit that is jointly-owned by Wyoming Electric (40 MW) and South Dakota Electric (55 MW).

(d)	Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by South Dakota Electric. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23% interest. Our adjacent WRDC mine supplies all of the fuel for the plant.

(e)	Wyodak Plant, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by South Dakota Electric. This baseload plant is operated by PacifiCorp and our WRDC mine supplies all of the fuel for the plant.

---

(a)	Included in the Price per MWh for Diesel Oil are unit start-up costs. The diesel-fueled generating units are generally used as supplemental peaking units and the cost per MWh is reflective of how often the units are started and how long the units are run.

(a)	Wind represents approximately 6%, 6% and 6% of our purchased power in 2019, 2018, and 2017, respectively.

---

(a)

South Dakota Electric owns 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western and eastern United States, respectively. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids. See Note 4 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

•	Shared Services Agreements -

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

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

◦	South Dakota Electric and BHSC are parties to a shared facilities agreement, whereby BHSC is charged for the use of the Horizon Point facility that is owned by South Dakota Electric and BHSC provides certain operations and maintenance services at the facility.

◦	South Dakota Electric and Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.

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

---

(a)	Includes $121.3 million in 2019 rate base for the Common Use System formula rate that is updated annually and $17.1 million in rate base for the DC transmission tie that is based on the approved stated rate from 2005.

---

•

A quarterly ECA rider that allows us to recover forecasted increases or decreases in purchased energy and fuel costs, including the recovery for amounts payable to others for the transmission of the utility's electricity over transmission facilities owned by others, and the sharing of off-system sales margins, less certain operating costs (customer receives 90%). The ECA provides for not only direct recovery, but also for the issuance of credits for decreases in purchased energy, fuel costs and eligible energy resources.

•	An annual TCA rider that includes nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism.

•	A Clean Air Clean Jobs Act Adjustment rider rate that collects the authorized revenue requirement for the 40 MW combustion turbine placed in service on December 31, 2016 with rates effective January 1, 2017.

•	A Renewable Energy Standard Adjustment rider that is specifically designed for meeting the requirements of Colorado’s renewable energy standard and most recently includes cost recovery for Peak View.

•

An approved annual EIA tariff which recovers costs associated with generation plant environmental improvements. South Dakota Electric also has a TFA tariff which recovers the costs associated with transmission facility improvements. The EIA and TFA were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to extend the 6-year moratorium period by an additional 3 years whereby rate increases for these recovery mechanisms will not go into effect prior to July 1, 2026. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

•

An annual cost adjustment clause which provides for the over or under recovery of fuel, transmission and purchased power cost incurred to serve South Dakota customers. Additionally, this ECA contains an off-system sales sharing mechanism in which South Dakota customers will receive a credit equal to 100% of off-system power marketing operating income from the first $1.0 million of power marketing margin from short-term sales and a credit equal to 70% of power marketing margins from short-term sales in excess of the first $1.0 million. South Dakota Electric retains the remaining 30%. For the period of July 1, 2017 through March 31, 2023, the 100% credit of power marketing margin increased from $1.0 million to $2.0 million. The ECA methodology allows us to directly assign renewable resources and firm purchases to the customer load. In Wyoming, a similar fuel and purchased power cost adjustment is also in place.

•	An approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff.

---

•	An annual cost adjustment mechanism that allows us to pass the prudently-incurred power costs above costs included in base rates through to electric customers. The annual cost adjustment allows for recovery of 85% of coal and coal-related cost per kWh variances from base and recovery of 95% of purchased power, transmission, and natural gas cost per kWh variances from base.

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

---

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

(b)	Total MWh includes Other Uses, Losses or Generation, net, which is approximately 5%, 6%, and 6% for Colorado Electric, South Dakota Electric and Wyoming Electric, respectively.

(c)

Due to the changes in our segment disclosures discussed in Note 5 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K, cost of fuel and purchased power was revised for the years ended December 31, 2018 and December 31, 2017 which resulted in an increase of $6.7 million and $6.0 million, respectively. There were corresponding decreases to Gross margin for both years. These changes had no impact on consolidated financial results.

(d)	For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

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

---

---

(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.

---

(a)	Arkansas Gas return on rate base is adjusted to remove current liabilities from rate review capital structure for comparison with other subsidiaries.

(b)	Arkansas Gas rate base is adjusted to include current liabilities for comparison with other subsidiaries.

(c)	Total Nebraska Gas Distribution rate base of $87.6 million includes amounts allocated to serve non-jurisdictional customers. Jurisdictional Nebraska rate base totals $69.8 million and is used for calculation of jurisdictional base rates.

---

(a)	The Wyoming Gas integrity rider is effective March 1, 2020.

---

(a)	For further information on Gross Margin, see “Non-GAAP Financial Measure” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

---

•

Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% maximum annual retail rate impact for compliance with the electric resource standards. The electric resource standards require our Colorado Electric subsidiary to generate, or cause to be generated, electricity from renewable energy sources equaling: (i) 20% of retail sales from 2015 to 2019; and (ii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) is limited to 2%. The standard encourages the CPUC to consider earlier and timely cost recovery for utility investment in renewable resources, including the use of a forward rider mechanism. We have been and currently remain in compliance with these standards.

•

Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, South Dakota Electric filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable “cost cap” included in the standards. In March 2013, the Montana Legislature adopted legislation that had the effect of excluding South Dakota Electric from all renewable portfolio standard requirements under State Senate Bill 164, primarily due to the very low number of customers South Dakota Electric has in Montana and the relatively high cost of meeting the renewable requirements.

•	South Dakota. South Dakota has adopted a renewable portfolio objective that encourages, but does not mandate utilities to generate, or cause to be generated, at least 10% of their retail electricity supply from renewable energy sources by 2015.

•	Wyoming. Wyoming currently has no renewable energy portfolio standard.

---

(a)	The Wygen I generation facility is a mine-mouth, coal-fired power plant with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. We own 76.5% of the plant and MEAN owns the remaining 23.5%.

(b)	On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in Busch Ranch I. This facility originally qualified under the Section 1603 program grant in lieu of ITCs.

(c)	On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II.

(d)	On February 5, 2019, Black Hills Electric Generation purchased 80 MW of wind generating assets in Iowa. A third-party operates the facility and we sell the wind energy generated in the MISO market.

(e)	This facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service.

---

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

(b)

Under the 20-year economy energy PPA (discussed in Note 19 of the Notes to the 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.

(c)	Black Hills Electric Generation amounts in this table are related to wind facilities held by our Power Generation segment. Change from 2018 to 2019 is driven by acquisition, and placing in service, of new wind assets.

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

•	Operating and Maintenance Services Agreement

◦

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

---

•	Shared Services Agreements

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

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

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

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

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

---

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

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

•

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

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

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

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

---

---

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

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

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

---

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

ITEM 1A.	RISK FACTORS

---

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

•

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

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

•

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

---

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

•

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

•

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

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

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

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

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

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

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

---

---

---

---

---

---

ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 3.	LEGAL PROCEEDINGS

---

---

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

---

ITEM 6.	SELECTED FINANCIAL DATA

---

(a)

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

(b)

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

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

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

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

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

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

---

---

---

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

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

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

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

---

---

---

•	Electric Utilities’ adjusted operating income increased $4.4 million due to reduced purchased power capacity costs, increased rider revenues and the prior year Wyoming Electric PCA settlement partially offset by higher operating expenses driven by outside services and employee costs;

•	Gas Utilities’ adjusted operating income increased $4.7 million primarily due to new customer rates and rider revenues, customer growth and increased transport and transmission driven by increased volumes from new and existing customers partially offset by higher operating expenses driven by outside services and employee costs;

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

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

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

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

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

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

---

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

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

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

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

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

•	Increased tax benefit of $97 million primarily due to a $73 million tax benefit resulting from legal entity restructuring and a reduction in the federal corporate income tax rate from 35% to 21% from the TCJA, effective January 1, 2018.

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

---

•

On December 13, 2019, Colorado Electric issued a request for proposals for its Renewable Advantage program, to potentially add up to 200 MW of renewable energy to its southern Colorado system. A competitive solicitation process for the addition of cost-effective, utility-scale renewable energy projects includes wind, solar and battery storage to supplement existing natural gas and wind generation power supplies Bidders have until February 15, 2020, to submit proposals, which will be reviewed by an independent evaluator overseen by the CPUC. Based on the outcome of the bidding process, projects would be placed in service no later than 2023.

•

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

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

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

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

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

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

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

•	Cooling degree days for the year ended December 31, 2019 were 14% higher than the normal compared to 29% higher than normal in 2018.

•	Heating degree days for the year ended December 31, 2019 were 5% higher than normal compared to 3% higher than normal in 2018.

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

◦

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

◦

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

---

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

•

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

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

•	On November 26, 2019, Black Hills Electric Generation placed in service Busch Ranch II. Through a competitive bidding process, Black Hills Electric Generation was selected to deliver renewable energy under a 25-year PPA to Colorado Electric.

•

On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and for 20 additional years. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC.

•	In October 2019, negotiations were completed for the price reopener in the contract with the Wyodak power plant. Effective July 1, 2019, the new price was reset at $17.94 per ton with customary escalators, compared to the prior contract price of $18.25 per ton. The contract expires on December 31, 2022 and negotiations are underway to extend the contract.

•	On October 3, 2019, we completed a public debt offering of $700 million in senior unsecured notes. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020 and repay a portion of short-term debt.

•	During the year ended December 31, 2019, we issued a total of 1.3 million shares of common stock for net proceeds of $99 million under our ATM equity offering program.

•	On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million and extended the term through June 17, 2021 on substantially similar terms and covenants. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

---

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

---

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

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

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

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

---

---

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

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

---

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

(b)	Wygen I experienced a planned outage in 2018

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

---

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

---

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

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

•	A current year $1.9 million tax benefit from increased repair activity in flow-through regulatory jurisdictions;

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

•	A current year $3.4 million tax benefit from a federal tax loss carry-back claim including interest. We identified certain qualified expenses that extend beyond the typical two-year carry-back period.

---

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

---

---

---

•	We issued a total of 1.3 million shares of common stock under the ATM equity offering program for proceeds of $99 million, net of $1.2 million in issuance costs.

•

On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. The debt offering consisted of $400 million of 3.05% 10-year senior notes due October 15, 2029, and $300 million of 3.875% 30-year senior notes due October 15, 2049. Proceeds were used to repay the $400 million Corporate term loan due June 17, 2021, retire the $200 million 5.875% senior notes due July 15, 2020, and repay a portion of short-term debt.

---

•

On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million, extended the term through June 17, 2021 and continued to have substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds were used to pay down short-term debt. Proceeds from the October 3, 2019 debt transaction were used to repay this term loan.

•	Short-term borrowings from our Revolving Credit Facility and CP Program.

•	Renew our shelf registration and ATM;

•	Continued equity issuance under the ATM or assess other equity issuance options;

•	Refinance a portion of short-term borrowings held through the Revolving Credit Facility and CP Program to long-term debt; and

•	Continue to assess debt and equity needs to support our capital expenditure plan.

•	Cash earnings (income from continuing operations plus non-cash adjustments) were $37 million higher than prior year driven primarily by higher margins at our Electric and Gas Utilities;

•	Net outflows from operating assets and liabilities were $25 million higher than prior year, primarily attributable to:

•	Cash outflows increased by approximately $40 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of higher outside services, employee costs and other working capital requirements;

•	Cash inflows increased by approximately $59 million compared to the prior year primarily as a result of lower accounts receivable driven by lower pass-through revenues reflecting lower commodity prices; and

•	Cash inflows decreased by approximately $44 million primarily as a result of changes in our current regulatory liabilities due to the TCJA tax rate change that has subsequently been returned to customers and from changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity prices; and

•	Cash outflows decreased approximately $5.5 million due to the absence of operating activities of discontinued operations in 2019.

---

•

Capital expenditures of approximately $818 million in 2019 compared to $458 million in 2018. The $361 million increase from the prior year was due to higher capital expenditures driven by higher programmatic safety, reliability and integrity spending at our Electric and Gas Utilities segments, the Corriedale Wind Energy Project at our Electric Utilities segment, construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska, at our Electric Utilities segment, the 35-mile Natural Bridge pipeline project at our Gas Utilities segment, and construction of Busch Ranch II at our Power Generation segment; and

•	Net cash used in investing activities decreased $4.0 million due to prior year activities associated with divesting of our oil and gas segment.

•	Increase of $539 million due to issuances of long and short-term debt in excess of required maturities that were used to fund our capital program

•	Decrease of $199 million in common stock issued primarily due to prior year gross proceeds of approximately $299 million from the Equity Unit conversion partially offset by current year net proceeds of $99 million through our ATM equity offering program;

•	Cash dividends on common stock of $125 million were paid in 2019 compared to $107 million paid in 2018; and

•	Cash outflows for other financing activities increased by approximately $5.5 million driven primarily by current year financing costs incurred in the October 3, 2019 debt transaction.

---

(a)	Includes accruals for property, plant and equipment as disclosed in Note 17 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(b)	Current year capital expenditures at our Electric Utilities segment increased due to higher programmatic safety, reliability and integrity spending, the Corriedale wind project and construction of the final segment of the 175-mile transmission line from Rapid City, South Dakota, to Stegall, Nebraska.

(c)	Current year capital expenditures at our Gas Utilities segment increased due to higher programmatic safety, reliability and integrity spending and the 35-mile Natural Bridge pipeline project.

(d)	Current year capital expenditures at our Power Generation segment increased due to construction of Busch Ranch II.

---

(a)	On February 28, 2019, S&P affirmed our BBB+ rating and maintained a Stable outlook.

(b)	On December 20, 2019, Moody’s affirmed our Baa2 rating and maintained a Stable outlook.

(c)	On August 29, 2019, Fitch affirmed our BBB+ rating and maintained a Stable outlook.

(a)	On April 30, 2019, S&P affirmed A rating.

(b)	On December 20, 2019, Moody’s affirmed A1 rating.

(c)	On August 29, 2019, Fitch affirmed A rating.

---

(a)	Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2019.

(b)

Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas transportation and storage agreements. The energy charges under the PPAs are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2019 and price assumptions using existing prices at December 31, 2019. Our transmission obligations are based on filed tariffs as of December 31, 2019.

(c)	Includes leases associated with several office and operating facilities, communication tower sites, equipment and materials storage.

(d)	Represents estimated payments for AROs associated with long-lived assets primarily related to retirement and reclamation of natural gas pipelines, mining sites, wind farms and an evaporation pond. See Notes 1 and 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

(e)	Represents estimated employer contributions to the Defined Benefit Pension Plan, the Non-Pension Defined Benefit Postretirement Healthcare Plan and the Supplemental Non-Qualified Defined Benefit Plans through the year 2029 as discussed in Note 18 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(f)

Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including commodity related contracts that have a negative fair value at December 31, 2019. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table; (3) our $4.2 million liability for unrecognized tax benefits in accordance with accounting guidance for uncertain tax positions as discussed in Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

---

---

---

(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.

---

---

---

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

---

---

---

•

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•	We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

•

We read relevant regulatory orders issued by the Commissions, procedural memorandums, filings made by the Company, and other publicly available information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions.

•	We obtained an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

---

---

---

---

---

---

---

---

(1)	BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

---

---

---

---

(a)	The 2018 addition is related to the Busch Ranch 1 contract intangible asset. See Note 4 for further information.

(b)	Amortization expense for existing intangible assets is expected to be $1.1 million for each year of the next five years.

---

---

•	Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

•	Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred

---

---

---

•

Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under tariff rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs.

•

Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered.

---

•

Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered.

•

Other non-regulated services - Our Electric and Gas Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided.

---

(a)

Due to the changes in our segment disclosures discussed in Note 5, Power Generation Wholesale revenue was revised for the year ended December 31, 2018, which resulted in an increase of $38 million. The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million. There was no impact to our consolidated Total Revenues.

(a)	The plant acquisition adjustment is included in rate base and is being recovered with 11 years remaining.

(b)

Due to the changes in our segment disclosures discussed in Note 5, Total electric plant in service, Accumulated depreciation and amortization, and Electric plant net of accumulated depreciation and amortization were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million, $91 million and ($170) million, respectively. There was no impact on our consolidated Plant, property and equipment.

---

(a)	Depreciation of Cushion gas is determined by the respective regulatory jurisdiction in which the Cushion gas resides.

(a)	Due to the changes in our segment disclosures discussed in Note 5, Property, plant and equipment, Accumulated depreciation and amortization, and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of $261 million, ($73) million and $188 million, respectively. There was no impact on our consolidated Plant, property and equipment.

---

(a)	Due to the changes in our segment disclosures discussed in Note 5, Corporate Accumulated depreciation and amortization and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($18) million and ($18) million respectively. There was no impact on our consolidated Plant, property and equipment.

•

South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

•

South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC and SPP regions. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie.

•

South Dakota Electric owns 52% of the Wygen III generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies fuel to Wygen III for the life of the plant.

•	Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. Black Hills Wyoming retains responsibility for plant operations.

---

---

(a)	Due to the changes in our segment disclosures, Electric Utilities and Power Generation Total assets were revised as of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million, respectively. There was no impact on our consolidated Total assets.

(a)	Includes accruals for property, plant and equipment as disclosed in Note 17.

(a)	Due to the changes in our segment disclosures, Electric Utilities and Power Generation Property, Plant and Equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million and $261 million, respectively. There was no impact on our consolidated Property, Plant and Equipment.

---

(a)	In 2019 we recorded an impairment of our investment in equity securities of a privately held oil and gas company. See Note 1 for additional information.

---

(a)	Income tax benefit (expense) includes a tax benefit of $73 million resulting from legal entity restructuring. See Note 15.

(b)	Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2018, which resulted in an increase (decrease) as follows (in millions):

---

(a)	Discontinued operations includes oil and gas property impairments. See Note 21.

(b)	Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2017, which resulted in an increase (decrease) as follows (in millions):

---

(a)	Variable interest rate.

(b)	Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2019 and December 31, 2018, respectively.

---

---

•	Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2019, the restricted net assets at our Electric and Gas Utilities were approximately $156 million.

•	Wyoming Electric and South Dakota Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements.

(a)	Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

---

---

(a)	The increase in Electric Utilities Revisions to Prior Estimates was primarily driven by an increase to the estimated cost to decommission certain regulated wind farm assets.

(b)	The changes in the Mining Revision to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process.

(c)	We reclassified $0.3 million of ARO as of December 31, 2018 related to Busch Ranch I from Electric Utilities to the Power Generation segment as a result of Black Hills Electric Generation’s purchase of its 50% ownership interest in Busch Ranch I. Additional liabilities were incurred in 2019 from new wind assets.

•	Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, market speculation, pipeline constraints, and other factors that may impact natural gas supply and demand;

•	Interest rate risk associated with our variable debt as described in Notes 6 and 7.

---

(a)	Term reflects the maximum forward period hedged.

(b)	As of December 31, 2019, 1,415,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.

(c)	Volumes exclude contracts that qualify for normal purchase, normal sales exception.

---

---

---

---

---

(a)	Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy.

(b)	Notes payable consist of commercial paper borrowings. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy.

(c)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.

---

---

(a)	The grant date fair values for the performance shares granted in 2019, 2018 and 2017 were determined by Monte Carlo simulation using a blended volatility of 21%, 21% and 23%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

---

---

(a)	Recovery of costs, but we are not allowed a rate of return.

(b)	In addition to recovery of costs, we are allowed a rate of return.

(c)	In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.

---

---

---

---

---

---

(a)	Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance.

---

---

(a)	Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability.

(b)	Legal entity restructuring - see above.

---

(a)	The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded.

(b)

Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method.

(c)

On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. During the year ended December 31, 2018, we recorded $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded $7.6 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017.

(d)	Legal entity restructuring - see above.

(e)	Primarily TCJA - see above.

(a)	The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.

---

---

---

---

---

(a)

Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.

---

---

(a)	Assets of VEBA trusts.

---

---

(a)	The estimated discount rate for the Defined Benefit Pension Plan is 3.27% for the calculation of the 2020 net periodic pension costs.

(b)	The expected rate of return on plan assets is 5.25% for the calculation of the 2020 net periodic pension cost.

---

•	Colorado Electric’s PPA with PRPA to purchase up to 60 MW of wind energy upon construction of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030.

•	Colorado Electric’s PPA with PRPA to purchase 25 MW of unit contingent energy. This agreement will expire June 30, 2024.

•	South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants.

•	South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp expiring December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.

•	South Dakota Electric’s PPA with PRPA to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029.

•	Wyoming Electric’s PPA with Happy Jack, expiring September 3, 2028, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric.

•	Wyoming Electric’s PPA with Silver Sage, expiring September 30, 2029, provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energy from Silver Sage to South Dakota Electric.

---

•

Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20-year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit.

(a)	On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm.

---

•	During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023.

•	South Dakota Electric has an agreement to provide MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023.

•

During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement which is renewed annually on September 3, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

---

•

South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires May 31, 2028. The contract terms are from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:

•	South Dakota Electric has an agreement that expires December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals.

---

(a)	We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

(b)	BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of Busch Ranch II. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations.

---

---

---

---

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

ITEM 9A.	CONTROLS AND PROCEDURES

ITEM 9B.	OTHER INFORMATION

---

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

(1)

Includes 146,179 full value awards outstanding as of December 31, 2019, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares, STIP or common stock units. In addition, 192,120 shares of unvested restricted stock were outstanding as of December 31, 2019, which are not included in the above table because they have already been issued.

(2)	Shares available for issuance are from the 2015 Omnibus Incentive Plan. The 2015 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

---

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

3.	Exhibits

---

---

---

*	Previously filed as part of the filing indicated and incorporated by reference herein.

†	Indicates a board of director or management compensatory plan.

ITEM 16.	FORM 10-K SUMMARY

---