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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

(a)	The July 2018 summer peak load of 254 surpassed previous summer peak record load of 249 set in July 2017. The December 2018 winter peak load of 238 surpassed the previous winter peak record load of 230 set in December 2016.

(b)	The July 2018 summer peak load of 413 surpassed previous summer peak record load of 412 set in July 2016. The October 2018 winter peak load of 313 surpassed previous winter peak load of 310 set in February 2011.

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(a)	Cheyenne Prairie, a 132 MW natural gas-fired power generation facility supports 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).

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

(c)	Wyodak, 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 coal mine supplies all of the fuel for the plant.

(d)

Busch Ranch I Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and Black Hills Electric Generation owns the remaining 50%. Black Hills Electric Generation purchased the remaining 50% from AltaGas on December 11, 2018. Colorado Electric has a PPA with Black Hills Electric Generation for its 14.5 MW of power from the wind farm. The terms of the PPA are the same as the previous PPA with AltaGas.

(e)	On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation for the 60 MW Busch Ranch II wind project. The project is currently under construction and is expected to be in service by the end of 2019.

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(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 7% of our purchased power in 2018, 2017, and 2016, respectively.

•	South Dakota Electric’s PPA with PacifiCorp expiring on December 31, 2023, which provides for the purchase of 50 MW of coal-fired baseload power;

•	Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031, which provides 200 MW of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is reported and accounted for as a capital lease within our business segments and is eliminated on the accompanying Consolidated Financial Statements;

•	Colorado Electric’s PPA with Black Hills Electric Generation, which provides up to 14.5 MW of wind energy from Black Hills Electric Generation’s owned interest in the Busch Ranch I Wind Farm. This PPA is the same as the previous agreement with AltaGas, which expires on October 16, 2037;

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Wyoming Electric’s PPA with Black Hills Wyoming expiring on December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019. On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019.

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•	Wyoming Electric’s 20-year PPA with Duke Energy expiring on September 3, 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility’s output to South Dakota Electric;

•	Wyoming Electric’s 20-year PPA with Duke Energy expiring on September 30, 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of the facility’s output to South Dakota Electric;

•	Wyoming Electric and South Dakota Electric’s Generation Dispatch Agreement requires South Dakota Electric to purchase all of Wyoming Electric’s excess energy; and

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

•	MDU owns a 25% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, South Dakota Electric will provide MDU with 25 MW from its other generation facilities or from system purchases with reimbursement of costs by MDU;

•	South Dakota Electric has an agreement through December 31, 2023 to provide MDU capacity and energy up to a maximum of 50 MW;

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The City of Gillette owns a 23% interest in Wygen III’s net generating capacity for the life of the plant. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, South Dakota Electric will provide the City of Gillette with its first 23 MW from its other generation facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, South Dakota Electric will also provide the City of Gillette its operating component of spinning reserves;

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

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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 in 2028. The terms of the contract run 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:

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(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 United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the SPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. South Dakota Electric’s electric system is located in the WECC region. 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.

•	Shared Services Agreements -

◦	South Dakota Electric, Wyoming Electric, and Black Hills Wyoming are parties to a shared facilities agreement, whereby each entity charges for the use of assets 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 Wyoming Electric receive certain staffing and management services from BHSC for Cheyenne Prairie.

•	Jointly Owned Facilities -

◦	South Dakota Electric, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby South Dakota Electric charges the City of Gillette and MDU for administrative services, plant operations and maintenance for its share of the Wygen III generating facility for the life of the plant.

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◦	Colorado Electric and Black Hills Electric Generation are parties to a shared joint ownership agreement whereby Colorado Electric charges Black Hills Electric Generation for operations and maintenance for its share of the Busch Ranch I Wind Farm.

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An approved annual Environmental Improvement Adjustment (EIA) tariff which recovers costs associated with generation plant environmental improvements. South Dakota Electric also has a Transmission Facility Adjustment (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. See Note 13 in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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An annual adjustment clause which provides for the over or under recovery of fuel 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%. During the six-year moratorium period effective July 1, 2017, 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 costs of fuel and purchased power 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.

•	An approved FERC Transmission Tariff that determines the revenue component of Wyoming Electric’s open access transmission tariff.

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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.

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

(b)	30-Year Average is from NOAA Climate Normals.

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(a)	Other revenue in 2018 reflects the impact of revenue reserved in accordance with the TCJA.

(b)	Non-GAAP measure.

(a)	Non-GAAP measure.

(b)	Total MWh includes Other Uses, Losses or Generation, net, which is approximately 6%, 6%, and 7% for South Dakota Electric, Wyoming Electric, and Colorado Electric, respectively.

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(a)	Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.

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(a)

Arkansas Gas has a weather normalization mechanism in effect during the months of November through April for customers with residential and certain business rate schedules. Kansas Gas has a weather normalization mechanism within its residential and business rate structure. The weather normalization mechanism in Arkansas differs from that in Kansas in that it only uses one location to calculate the weather, while Kansas uses multiple locations. The weather normalization mechanisms in both Arkansas and Kansas minimize weather impact on gross margins (a non-GAAP measure).

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

(c)	30-Year Average is from NOAA climate normals.

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(a)	Arkansas Gas return on rate base adjusted to remove current liabilities from rate case 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 and agricultural customers. Jurisdictional Nebraska rate base of $69.8 million excludes those amounts allocated to serve non-jurisdictional and agricultural customers and is used for calculation of jurisdictional base rates.

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(a)	Non-GAAP measure.

(b)	Other revenue and Gross Margin in 2018 reflects the impact of revenue reserved in accordance with the TCJA.

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(a)	Non-GAAP measure.

(a)	The decrease is 2018 is due to customer class reclassification to residential at our Colorado Gas utilities.

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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 are currently in compliance with these standards.

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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.

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(a)	Black Hills Colorado IPP owns and operates this facility. This facility provides capacity and energy to Colorado Electric under a 20-year PPA with Colorado Electric. This PPA is accounted for as a capital lease on the accompanying Consolidated Financial Statements.

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

(b)	The decrease in 2017 was driven by the joint dispatch agreement Colorado Electric joined in 2017. See details of this agreement above in the Electric Utilities segment.

(c)	The decrease in 2018 was driven by a planned outage at Wygen I.

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•	Economy Energy PPA and other ancillary agreements

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Black Hills Wyoming has ancillary agreements with the City of Gillette, Wyoming to operate CTII, and provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreements include 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.

•	Operating and Maintenance Services Agreement

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In conjunction with the sale of the noncontrolling interest on April 14, 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 is in effect from 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 charges 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 Generating Station.

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

•	Jointly Owned Facilities

◦	Black Hills Wyoming and MEAN are parties to a shared joint ownership agreement, whereby Black Hills Wyoming charges MEAN for administrative services, plant operations and maintenance on its share of the Wygen I generating facility over the life of the plant.

◦	Black Hills Electric Generation and Colorado Electric both own 50% of the Busch Ranch I Wind Farm. Black Hills Electric Generation purchased its 50% share in Busch Ranch I from AltaGas on December 11, 2018. See details of the PPA and ownership agreement discussed previously in the Electric Utilities segment.

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

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The 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by South Dakota Electric. PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. South Dakota Electric is also obligated to purchase a minimum of 0.375 million tons of coal per year for its 20% share of the power plant, subject to adjustments for planned outages. This contract expires December 31, 2022;

•	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 of coal 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 of coal 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 of coal each year. These contracts have terms of one to five years.

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

•	In Arkansas, Nebraska, Iowa, Colorado, Kansas and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 805,000 square feet utilized by our Gas Utilities.

•	In South Dakota, Wyoming, Colorado and Montana we own various office, service center, storage, shop and warehouse space totaling approximately 240,000 square feet utilized by our Electric Utilities and Mining segments.

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(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.

ITEM 1A.	RISK FACTORS

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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;

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Interruptions to supply of fuel and other commodities used in generation and distribution. Our utilities purchase fuel from a number of suppliers. Our results of operations could be negatively impacted by disruptions in the delivery of fuel 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;

•	Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical service facilities and equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;

•	Operating hazards such as leaks, mechanical problems and accidents, including explosions affecting our natural gas distribution system, which could impact public safety, reliability and customer confidence;

•	Operational limitations imposed by environmental and other regulatory requirements;

•	Breakdown or failure of equipment or processes, including those operated by PacifiCorp at the Wyodak Plant;

•	Labor relations. Approximately 25% of our employees are represented by a total of eight collective bargaining agreements;

•	Our ability to transition and replace our retirement-eligible utility employees. At December 31, 2018, approximately 18% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement;

•	Inability to recruit and retain skilled technical labor; and

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

•	The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;

•	Contractual restrictions upon the timing of scheduled outages;

•	The cost of supplying or securing replacement power during scheduled and unscheduled outages;

•	The unavailability or increased cost of equipment;

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•	The cost of recruiting and retaining or the unavailability of skilled labor;

•	Supply interruptions, work stoppages and labor disputes;

•	Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations;

•	Opposition by members of public or special-interest groups;

•	Weather interferences;

•	Availability and cost of fuel supplies;

•	Unexpected engineering, environmental and geological problems; and

•	Unanticipated cost overruns.

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•	Our inability to obtain required governmental permits;

•	Our inability to complete capital projects in a timely manner;

•	Our inability to secure just and reasonable utility rates through regulatory proceedings;

•	Our inability to obtain financing on acceptable terms, or at all;

•	The possibility that one or more credit rating agencies would downgrade our issuer credit rating to below investment grade, thus increasing our cost of doing business;

•	Our inability to attract and retain management or other key personnel;

•	Our inability to negotiate acceptable construction, fuel supply, power sales or other material agreements;

•	Reduced growth in the demand for utility services in the markets we serve;

•	Changes in federal, state, local or tribal laws and regulations, particularly those which would make it more difficult or costly to fully develop our coal reserves or our power generation capacity;

•	Fuel prices or fuel supply constraints;

•	Pipeline capacity and transmission constraints;

•	Competition within our industry and with producers of competing energy sources; and

•	Changes in tax rates and policies.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 3.	LEGAL PROCEEDINGS

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

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ITEM 6.	SELECTED FINANCIAL DATA

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(a)	The increase in 2016 includes the debt associated with the SourceGas acquisition (see Note 6 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K).

(b)

On November 1, 2017, we made the decision to divest our Oil and Gas assets. 2017 includes an 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 ceiling test impairment charges to crude oil and natural gas properties of $158 million and a non-cash after-tax equity investment impairment charge of $2.9 million (see Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K).

(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 2018, 2017 and 2016 was reduced by $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest.

(d)	2017, 2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively. 2016 and 2015 also include after-tax internal labor costs attributable to the SourceGas Acquisition of $9.1 million and $3.0 million that otherwise would have been charged to other segments.

(e)	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. In November 2015, we issued 6.3 million shares of common stock, par value $1.00 per share at a price of $40.25.

(f)	Calculated based on Net income (loss) from continuing operations available for common stock.

(g)	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.

(h)

Net income (loss) from continuing operations for the year ended December 31, 2018 included approximately $4.0 million of income tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. The (expense) benefit impact to our operating segments and Corporate and Other for the year ended December. 31, 2018 was: Electric Utilities ($4.2) million; Gas Utilities $0.5 million; Power Generation ($0.7) million; Mining ($0.5) million; and Corporate and Other $0.9 million, respectively. Net Income from continuing operations for the year ended December 31, 2017 includes a net tax benefit of $7.6 million from the revaluation of deferred tax balances due to a decrease in the statutory Federal income tax rate resulting from the TCJA. The (expense) benefit impact to our operating segments and Corporate and Other for the year ended December 31, 2017 was: Electric Utilities $23 million; Gas Utilities ($6.8) million; Power Generation $24 million; Mining $2.7 million; and Corporate and Other ($35) million, respectively.

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ITEMS 7 &	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS

and 7A.	OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET

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•	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.

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(a)

Income (loss) from continuing operations for 2018 included approximately $4.0 million of income tax expense associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes. Income from continuing operations for 2017 includes a net tax benefit of $7.6 million from the revaluation of deferred tax balances due to a decrease in the statutory Federal income tax rate resulting from the TCJA. See the table below for the impact to each segment for both years.

(b)	Income (loss) from continuing operations for 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.

(c)	Income from continuing operations for 2017 includes a $4.1 million tax benefit from a true-up to the filed 2016 SourceGas tax returns relating to the SourceGas Acquisition.

(d)	On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income (loss) from continuing operations available for common stock for 2018, 2017 and 2016 was reduced by $14 million, $14 million and $9.6 million, respectively, attributable to this noncontrolling interest.

(e)	Income from continuing operations for 2017 and 2016 include incremental SourceGas Acquisition costs, after-tax of $2.8 million and $30 million, respectively and after-tax internal labor costs attributable to the SourceGas Acquisition of $0.5 million and $9.1 million, respectively, that otherwise would have been charged to other business segments.

(f)	Income from continuing operations for 2016 included tax benefits of approximately $4.4 million as a result of the re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.

(g)	Loss from discontinued operations in 2017 and 2016 included non-cash after-tax impairments of crude oil and natural gas properties of $13 million and $67 million, respectively. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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Gas Utilities’ earnings, excluding tax reform impacts, increased approximately $87 million primarily due to the recognition of 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); earnings also benefited from colder winter weather and increased sales of natural gas, offset by an increase in operating expenses;

•	Earnings at our Mining segment, excluding tax reform impacts, increased $1.7 million primarily due to increased price per ton sold and lower operating expenses;

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Electric Utilities’ earnings, excluding tax reform impacts, decreased by $3.5 million due primarily to a settlement agreement with the WPSC which decreased gross margins by $2.6 million; other variances to the prior year were due to higher operating expenses driven by facility costs, employee costs, contractor and consulting expenses, and vegetation management expenses, partially offset by higher rider revenues from recent transmission investments, higher power marketing and wholesale margins, and favorable weather;

•	Earnings at our Power Generation segment, excluding tax reform impacts, decreased $1.2 million primarily due to higher operating expenses;

•	Corporate and Other expenses, excluding tax reform impacts, increased by approximately $1.3 million primarily due to higher intercompany allocations of tax expense, partially offset by a decrease in acquisition and transition costs occurring in the prior year; and

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In 2018, we recorded $4.0 million of income tax (expense) associated with changes in the prior estimated impact of tax reform on regulatory liabilities and deferred income taxes compared to a net tax benefit of approximately $7.6 million as a result of the revaluation of deferred tax balances due to the decrease in the statutory Federal income tax rate as a result of the TCJA. The impacts to our operating segments and Corporate and Other for 2018 and 2017 were (in millions):

•	On December 17, 2018, South Dakota Electric and Wyoming Electric filed for approval with the SDPUC and WPSC, new voluntary renewable energy tariffs to serve customer requests for renewable energy resources. In addition, South Dakota Electric and Wyoming Electric filed a joint application with the WPSC for a CPCN to construct a $57 million, 40 MW wind generation project near Cheyenne, Wyoming.

•	On December 6, 2018, Wyoming Electric set a new all-time winter peak load of 238 MW, exceeding the previous winter peak of 230 MW set on December 7, 2016.

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On November 30, 2018, Wyoming Electric submitted its 2018 integrated resource plan to the WPSC, which included the recommendation that Wyoming Electric acquire Wygen I. Review of Wyoming Electric’s integrated resource plan is subject to an open public process governed by the WPSC. The purchase of Wygen I would require approval of a CPCN by the WPSC and approval by FERC. The review process is expected to be completed by year-end 2019.

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On October 31, 2018, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric will provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve several years of disputed issues related to PCA dockets before the commission. The settlement also stipulates that the adjustment for the variable cost segment of the Wygen I Power Purchase Agreement with Wyoming Electric (an affiliate company) will escalate by 3% annually through 2022.

•	On October 3, 2018, Colorado Electric set a new all-time winter peak load of 313 MW, exceeding the previous winter peak of 310 MW set in February 2011.

•	Cooling degree days for the year ended December 31, 2018 were 29% higher than the 30-year average (normal) compared to 14% higher than normal in 2017.

•	Wyoming Electric and Colorado Electric set new summer peak loads:

•	On July 10, 2018, Wyoming Electric set a new all-time peak load of 254 MW, exceeding the previous summer peak of 249 MW set in July 2017.

•	On June 27, 2018, Colorado Electric set a new all-time peak load of 413 MW, exceeding the previous summer peak of 412 MW set in July 2016.

•	On November 20, 2018, South Dakota Electric placed in service a 33-mile segment of a $70 million, 175-mile, 230-kV transmission line from Rapid City, South Dakota, to Stegall, Nebraska. The first 48-mile segment was placed in service on July 25, 2018. The remaining 94-mile segment is expected to be in service by the end of 2019.

•	On April 25, 2018, Colorado Electric received approval from the CPUC to contract with Black Hills Electric Generation for the 60 MW Busch Ranch II wind project. The project is currently under construction and is expected to be in service by the end of 2019. This renewable energy will enable Colorado Electric to comply with Colorado's Renewable Energy Standard.

•	Rate Review updates:

•	On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate the base rate areas, tariffs, terms and conditions and adjustment clauses of its two legacy utilities. The rate review also requests $2.5 million in new revenue to recover costs and investments, in safety, reliability and system integrity. See Note 13 for additional details.

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On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates will generate approximately $12 million of new revenue. The APSC’s approval also allows Arkansas Gas to include $11 million of revenue that is currently being collected through certain rider mechanisms in the new base rates. The new revenue increase is based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018.

•	On July 16, 2018, the WPSC approved our Wyoming Gas (Northwest Wyoming) settlement and stipulation with the OCA. The settlement provides for $1.0 million of new revenue, a return on equity of 9.6%, and a capital structure of 54.0% equity and 46.0% debt. New rates, inclusive of customer benefits related to the TCJA, were effective September 1, 2018.

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In Colorado, RMNG implemented new rates after approval of a settlement of a rate review filed in October 2017. The settlement included $1.1 million in annual revenue increases and an extension of SSIR to recover costs from 2018 through 2021. The annual increase is based on a return on equity of 9.9% and a capital structure of 46.63% equity and 53.37% debt. New rates are inclusive of customer benefits related to the TCJA.

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•	On November 20, 2018, Wyoming Gas received approval from the WPSC for a CPCN to construct a new $54 million, 35-mile natural gas pipeline to enhance supply reliability and delivery capacity for approximately 57,000 customers in central Wyoming. The pipeline, known as the Natural Bridge Pipeline, is planned to be in service in late 2019.

•

Certain legal entity restructuring transactions occurred on March 31, 2018 and December 31, 2018 as part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years. As a result of these transactions, additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, were recorded with a corresponding deferred tax benefit recorded on the Consolidated Statements of Income.

•	Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than the 30-year average (normal) compared to 10% lower than normal in 2017.

•	On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in the 29 MW Busch Ranch I Wind Farm, previously owned by AltaGas, for $16 million.

•	On April 25, 2018, Black Hills Electric Generation was selected to provide 60 MW of renewable energy to Colorado Electric from the Busch Ranch II wind project, which is expected to be in service by the end of 2019.

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On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued in November 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds were used to pay off $250 million of debt maturing in January 2019 and other short-term debt.

•	On October 11, 2018, Fitch affirmed Black Hills’ credit rating at BBB+ and maintained a Stable outlook.

•	On August 17, 2018, we completed a public debt offering of $400 million principal amount of 4.350% senior unsecured notes. The proceeds were used to repay the $299 million principal amount of our RSNs due 2028 and pay down short-term debt.

•	On August 9, 2018, S&P upgraded Black Hills’ credit rating to BBB+ with a Stable outlook and South Dakota Electric’s credit rating to A.

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On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of$750 million and extending the term through July 30, 2023 with two one-year extension options (subject to consent from lenders). This facility is similar to the former Revolving Credit Facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and the banks increasing or providing new commitments, to increase total commitments of the facility up to $1.0 billion.

•	On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, matures on July 30, 2020.

•	On July 19, 2018, Fitch affirmed South Dakota Electric’s credit rating at A.

•	On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. As of December 31, 2018, we have completed the divestiture of our oil and gas assets. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

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Corporate and Other, excluding tax reform impacts, decreased by approximately $37 million compared to the same period in the prior year driven primarily by a $27 million reduction of after-tax external acquisition and transition costs, a reduction of approximately $8.6 million of internal labor attributed to the SourceGas Acquisition and lower reallocated discontinued operation expenses of approximately $2.9 million, partially offset by a $4.4 million tax benefit in 2016;

•	Gas Utilities’ earnings, excluding tax reform impacts, increased approximately $13 million, with a full year of earnings from our acquired SourceGas utilities compared to approximately 10.5 months in 2016; and a $4.1 million tax benefit recognized in 2017;

•	We recorded a net tax benefit of approximately $8 million as a result of the revaluation of deferred tax balances due to the decrease in the statutory Federal income tax rate as a result of the TCJA. This benefit’s impact to our operating segments and Corporate and Other was:

◦	Electric Utilities - $23 million tax benefit

◦	Gas Utilities - $6.8 million tax expense

◦	Power Generation - $24 million tax benefit

◦	Mining - $2.7 million tax benefit

◦	Corporate and Other - $35 million tax expense consisting of $28 million of tax expense from the revaluation of Corporate deferred tax balances and $7 million of tax expense from the revaluation of deferred taxes that were originally recorded to AOCI.

•	Electric Utilities’ earnings, excluding tax reform impacts, were comparable to the prior year reflecting an increase from returns on prior year generation investments, offset by higher employee costs and higher generation maintenance expenses;

•	Earnings at our Power Generation segment, excluding tax reform impacts, decreased $3.5 million primarily due to an increase in net income attributable to noncontrolling interests, reflecting a full year in 2017 compared to approximately 8.5 months in 2016; and

•	Earnings at our Mining segment, excluding tax reform impacts, increased approximately $1.6 million due to an increase in tons sold as a result of an extended outage in the prior year.

•	In our Electric Utilities service territories, winter weather was mostly comparable to the prior year and the summer was milder in 2017 compared to the prior year. Heating degree days in 2017 were 3% lower than normal compared to 11% lower than normal in 2016. Cooling degree days for the full year of 2017 were 29% higher than normal compared to 14% higher than normal in 2016.

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On January 17, 2017, Colorado Electric received approval from the CPUC on a settlement agreement for its electric resource plan which provides for the addition of 60 MW of renewable energy to be in service by 2019. The resource plan was filed June 3, 2016, to meet requirements under the Colorado Renewable Energy Standard. In the second quarter of 2017, Colorado Electric issued a request for proposals to acquire renewable energy resources to comply with the Colorado Renewable Energy Standard and presented the results to the CPUC on February 9, 2018. See the Electric Utilities 2018 highlights above for the outcome of this proposal.

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•	Construction was completed on the 144 mile transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

•	On July 19, 2017, Wyoming Electric set a new summer load peak of 249 MW, exceeding the previous summer peak of 236 MW set in July 2016.

•	Our service territories reported comparable year-over-year winter weather as measured by heating degree days compared to the 30-year average. Combined heating degree days for the full year in 2017 were 10% less than normal compared to 11% less than normal in the same period in 2016.

•	During the fourth quarter of 2017, Arkansas Gas, Wyoming Gas and RMNG all filed rate review applications with their respective state commissions. See the Gas Utilities 2018 highlights above for the outcomes of these rate reviews.

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On August 4, 2017, we renewed the ATM equity offering program, which reset the size of the program to an aggregate value of up to $300 million. The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million. We did not issue any common shares during the twelve months ended December 31, 2017.

•	2017 credit rating updates: On December 12, 2017, Moody’s affirmed Black Hills’ credit rating at Baa2 with a Stable outlook. On October 4, 2017, Fitch affirmed Black Hills’ credit rating at BBB+ rating and maintained a Stable outlook, and on July 21, 2017, S&P affirmed Black Hills’ credit rating at BBB rating and maintained a Stable outlook.

•	On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

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(a)	We estimated and recorded a reserve to revenue of approximately $22.3 million during year ended December 31, 2018 to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs. This reduction to revenues is offset by lower tax expense and has no impact on overall results.

(b)	Non-GAAP measure.

(c)	The year ended December 31, 2018 includes Horizon Point shared facility revenues of approximately $11 million, which are allocated to all of our operating segments as facility expenses. This shared facility agreement has no impact on BHC’s consolidated operating results.

(d)	Gross margin was impacted for the year ended December 31, 2018 by ($4.3) million as a result of the Wyoming Electric PCA settlement.

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(a)	2017 reflects planned outages at Neil Simpson II, Wyodak, and Wygen II.

(b)	2016 reflects a planned outage at Wygen III, an extended planned outage at Wyodak and an unplanned outage at Neil Simpson II.

(c)	2017 and 2016 were lower due to the addition of Peak View Wind Project with ownership transfer in November, 2016.

(a)	Non-GAAP measure

(b)	Horizon Point shared facility revenue is offset by facility expenses at our operating segments and has no impact on consolidated results.

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(a)	Non-GAAP measure

(b)	Includes approximately 1.5 months of Horizon Point shared facility revenue.

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(a)	We estimated and recorded a reserve to revenue of approximately $20.5 million during the year ended December 31, 2018 to reflect the lower federal income tax rate from the TCJA on our existing rate tariffs. This reduction to revenues is offset by lower tax expense and has no impact on overall results.

(b)	Non-GAAP measure.

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(a)	Non-GAAP measure

(b)	Heating degree days at the Gas Utilities for the year ended December 31, 2018 were 2% higher than the 30-year average (normal) compared to 10% lower than normal in 2017.

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(a)	Non-GAAP measure

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(a)	Wygen I experienced a planned outage in 2018.

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(a)	Increase in overburden in 2018 and 2017 compared to 2016 was due to relocating mining operations to areas of the mine with higher overburden.

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(a)	Includes certain general and administrative and interest expenses that are not reported as discontinued operations.

•	Prior year tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances as a result of the TCJA;

•	Higher current year state income tax expense of $4.6 million;

•	A decrease in corporate expenses from prior year acquisition costs; and

•	Lower interest costs due to interest expenses originally charged to our Oil and Gas Segment in 2017 which were not reclassified to discontinued operations in 2017, and were allocated to our operating segments in 2018.

•	Tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances as a result of the TCJA;

•	A decrease in after-tax acquisition and transition expenses of approximately $36 million, driven by lower external acquisition costs and lower internal labor attributed to the SourceGas Acquisition;

•	As a result of the Oil and Gas segment being reported as discontinued operations in 2017, indirect operating costs that would have been charged to this segment were reallocated to other business segments in 2017. These same costs in 2016 are reported as Corporate and Other;

•	A decrease of approximately $4.4 million in tax benefits; and

•	A decrease in other corporate expenses.

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(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.

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

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(a)	No commercial paper was issued from November 1, 2018 to December 11, 2018 due to excess cash on hand from the Equity Units settlement until we paid off the $250 million, 2.5% Senior unsecured notes due January 11, 2019.

•	Short-term borrowings from our CP Program.

•	On December 12, 2018, we paid off the $250 million, 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to repay this obligation.

•	On November 1, 2018, we completed settlement of the stock purchase contracts that are components of the Equity Units issued November 23, 2015. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. See Note 12 for more information.

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On August 17, 2018, we completed a public debt offering of $400 million principal amount, 4.350% senior unsecured notes due 2033. The proceeds were used to repay the $299 million principal amount of our RSNs due 2028 and pay down short-term debt. Through this offering, we successfully remarketed the $299 million principal amount of the existing subordinated notes, which were originally issued as a part of the Company's Equity Units on November 23, 2015. See Note 6 for more information.

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•	On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, will now mature July 30, 2020 and has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. See Note 6 for more information.

•	We did not issue any shares of common stock under our ATM equity offering program in 2018.

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•	Cash earnings (income from continuing operations plus non-cash adjustments) were $7 million lower than prior year driven primarily by impacts of customer refunds related to the TCJA tax decrease which lowered current year revenue;

•	Net inflow from operating assets and liabilities was $62 million higher than prior year, primarily attributable to:

•	Cash inflows increased by approximately $34 million as a result of changes in accounts payable and accrued liabilities, driven by the impact of energy commodity prices on our accounts payable, partially offset by the expiration of accrued contract payables related to Equity Units;

•	Cash outflows increased by approximately $43 million compared to the prior year as a result of higher accounts receivable driven by higher revenues, energy delivered and energy commodity prices; and

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Cash inflows increased by approximately $72 million primarily as a result of changes in our current regulatory assets driven by lower fuel cost adjustments and the impact of lower commodity price on our regulatory assets and from an increase in current regulatory liabilities driven by cash collections of income taxes from customer bills in excess of current tax rates subsequent to the TCJA that will be refunded in the future;

•	Cash outflows decreased by approximately $15 million due to additional pension contributions made in the prior year;

•	Cash inflows increased approximately $15 million for other operating activities compared to the prior year primarily due to the long-term expiration of accrued contract payables related to Equity Units; and

•	Cash outflows increased approximately $25 million due to operating activities of discontinued operations.

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Capital expenditures of approximately $458 million in 2018 compared to $326 million in 2017. The $132 million increase from the prior year was due to higher capital expenditures at our Electric and Gas Utilities which included additional transmission investments, and higher programmatic integrity capital at our Gas Utilities. Capital expenditures increased at our Power Generation segment due to the Busch Ranch I purchase, and from investments made to Wygen I. Capital investments also increased at our Mining segment as they purchased a new mining shovel in 2018.

•	A $24 million investment partially offset by a $13 million increase in net cash provided by investing activities from discontinued operations.

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•	Payments of long-term debt increased by $749 million due to current year payments on the $300 million term loan refinanced in July 2018, the retirement of $299 million of RSNs in August 2018 and the retirement of $250 million Senior unsecured notes in December 2018, compared to $100 million of principal payments made on term loans in the prior year;

•	Long-term borrowings increased by $700 million due to the issuance of $400 million senior secured notes in August 2018 and the refinancing of our $300 million unsecured term loan in July 2018;

•	Gross proceeds of approximately $299 million received in exchange for approximately 6.372 million shares of common stock from the Equity Unit conversion;

•	Net short-term debt payments increased by $140 million as a result of using proceeds from the Equity Unit conversion to pay down short-term debt;

•	Cash dividends on common stock of $107 million were paid in 2018 compared to $97 million paid in 2017;

•	Cash outflows for other financing activities increased by approximately $4.3 million driven primarily by higher financing costs incurred in the July 30, 2018 and August 17, 2018 debt transactions.

•	Cash earnings (income from continuing operations plus non-cash adjustments) were $68 million higher than prior year;

•	Net outflow from operating assets and liabilities was $16 million lower than prior year, primarily attributable to:

•	Cash outflows decreased by approximately $4.8 million as a result of changes in accounts payable and accrued liabilities driven by changes in working capital requirements;

•	Cash outflows decreased by approximately $20 million compared to the prior year as a result of lower accounts receivable due to warmer weather partially offset by higher natural gas inventory; and

•	Cash outflows increased by approximately $9.5 million primarily as a result of changes in our current regulatory assets and liabilities driven by differences in fuel cost adjustments and commodity price impacts compared to the same period in the prior year;

•	Cash outflows decreased by approximately $29 million as a result of interest rate swap settlements;

•	Cash outflows increased by approximately $14 million due to additional pension contributions made in 2017;

•	Cash outflows increased approximately $7.8 million for other operating activities compared to the prior year; and

•	Cash inflows decreased approximately $17 million due to operating activities of discontinued operations.

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•	In 2016 cash outflows included approximately $1.1 billion for the acquisition of SourceGas, net of $760 million long-term debt assumed (see Note 2 in Item 8 of Part II of this Annual Report on Form 10-K);

•	Capital expenditures of approximately $326 million in 2017 compared to $455 million in 2016. The $129 million variance to the prior year was due primarily to higher prior year capital expenditures at our Electric Utilities from generation investments at Colorado Electric; and

•	Cash inflows increased approximately $16 million due to investing activities of discontinued operations.

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Long-term borrowings decreased by $1.8 billion due to the 2016 financings which consisted of $693 million of net proceeds from the August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, $500 million of proceeds from the August 9, 2016 term loan, $546 million of net proceeds from our January 13, 2016 public debt offering used to partially finance the SourceGas Acquisition and proceeds from a $29 million term loan used to fund the early settlement of a gas gathering contract;

•	Payments on long-term debt decreased by $1.1 billion due to the 2016 refinancing of the $760 million of long-term debt assumed in the SourceGas Acquisition and lower current year payments on term loans, $106 million paid on term loans in 2017 compared to $400 million paid on term loans in 2016;

•	Proceeds of $216 million from the sale of a 49.9% noncontrolling interest of Black Hills Colorado IPP that took place in 2016 (see Note 12 in Item 8 of Part II of this Annual Report on Form 10-K);

•	Proceeds from common stock issuances decreased by $117 million primarily from issuing common stock under our ATM equity offering program in 2016;

•	Net short-term borrowings increased by $95 million primarily due to CP borrowings used to pay down long-term debt;

•	Cash dividends on common stock of $97 million were paid in 2017 compared to $88 million paid in 2016;

•	In 2017, distributions to noncontrolling interests increased by $8.8 million compared to 2016; and

•	Cash outflows for other financing activities decreased by approximately $16 million driven primarily by higher financing costs from the 2016 debt offerings and refinancings compared to a payment of $5.6 million for a redeemable noncontrolling interest in March 2017.

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(a)	Includes accruals for property, plant and equipment.

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(a)	On August 9, 2018, S&P upgraded to BBB+ rating and revised the outlook to Stable.

(b)	On December 12, 2018, Moody's affirmed Baa2 rating and maintained a Stable outlook.

(c)	On October 11, 2018, Fitch affirmed BBB+ rating and maintained a Stable outlook.

(a)	On August 9, 2018, S&P upgraded to A rating.

(b)	On December 12, 2018, Moody’s affirmed A1 rating.

(c)	On October 11, 2018, Fitch affirmed A rating.

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(a)	Long-term debt amounts do not include discounts or premiums on debt.

(b)	The following amounts are estimated for interest payments over the next five years which are not included within the long-term debt balances presented: $130 million in 2019, $126 million in 2020, $108 million in 2021, $108 million in 2022 and $102 million in 2023. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2018.

(c)

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 2018 and price assumptions using existing prices at December 31, 2018. Our transmission obligations are based on filed tariffs as of December 31, 2018.

(d)	Includes operating leases associated with several office buildings, warehouses and call centers, equipment and vehicles.

(e)	Includes estimated asset retirement obligations associated with our Electric Utilities, Gas Utilities and Mining segments as discussed in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

(f)	Represents both estimated employer contributions to Defined Benefit Pension Plan and payments to employees for the Non-Pension Defined Benefit Postretirement Healthcare Plans and the Supplemental Non-Qualified Defined Benefit Plans through the year 2028.

(g)

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, 2018. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; and (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.

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(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 the Busch Ranch II Wind Farm. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations. The guarantee decreases as progress payments are made.

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

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(a)	Excludes unamortized premium or discount.

(b)	Interest rates as of December 31, 2018.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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(1)	BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

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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 rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract 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 regulator-empowered statute to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs.

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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, Black

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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 coal supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons of coal delivered.

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Other non-regulated services - Our Gas and Electric 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.

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

(b)	Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years.

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(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.

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(a)	The plant acquisition adjustment is included in rate base and is being recovered with 12 years remaining.

(b)	Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031.

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(a)	Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides.

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(a)	Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $18 million.

(a)	Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million.

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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.

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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 region and the SPP region. 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.

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South Dakota Electric owns 52% of the Wygen III coal-fired 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 coal 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.

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(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

(b)	On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information.

(a)	Includes accruals for property, plant and equipment.

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(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.

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

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

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

(a)	Includes interest allocations in 2017 and 2016 of approximately $4.9 million and $5.6 million, respectively.

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(a)	Variable interest rate, based on LIBOR plus a spread.

(b)	See Note 12 for RSN details.

(c)	Variable interest rate.

(d)	Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2018 and December 31, 2017, respectively.

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•	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, 2018, the restricted net assets at our Electric and Gas Utilities were approximately $257 million.

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(a)	The Gas Utilities’ Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations.

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

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•	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.

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(a)	Term reflects the maximum forward period hedged.

(b)	As of December 31, 2018, 1,542,000 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.

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(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.

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

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(a)	The grant date fair values for the performance shares granted in 2018, 2017 and 2016 were determined by Monte Carlo simulation using a blended volatility of 21%, 23% and 24%, 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.

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(a)	The decrease in rent expense is primarily driven by current year expiration of office leases and by purchases of facilities previously leased.

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(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.

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(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 approximately $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 approximately $8.0 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.

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(a)

Certain investments that are measured at fair value using Net Asset Value “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.

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(a)

Certain investments that are measured at fair value using Net Asset Value “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 plans’ benefit obligations and fair value of plan assets above.

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(a)	Assets of VEBAs and Grantor Trust.

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(a)	Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year.

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(a)	The estimated discount rate for the Defined Benefit Pension Plan is 4.40% for the calculation of the 2019 net periodic pension costs.

(b)	The expected rate of return on plan assets is 6.00% for the calculation of the 2019 net periodic pension cost.

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•

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.

•	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.

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

•	Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, 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.

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

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

(b)	PPAs with Cargill expired on December 31, 2016.

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•	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, MDU will be provided 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 serve 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, we 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 expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves.

•	South Dakota Electric has a PPA with MEAN expiring May 31, 2028. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.

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

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(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 the Busch Ranch II Wind Farm. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations. The guarantee decreases as progress payments are made.

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(a)	Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods.

(b)	A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production.

(c)	For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54/Mcf for Piceance, $0.92/Mcf for San Juan and $0.53/Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable.

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

ITEM 9A.	CONTROLS AND PROCEDURES

ITEM 9B.	OTHER INFORMATION

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ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

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

(1)

Includes 187,362 full value awards outstanding as of December 31, 2018, 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, 235,748 shares of unvested restricted stock were outstanding as of December 31, 2018, 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

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ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

3.	Exhibits

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*	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

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