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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

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(a)	The July 2017 summer peak load of 249 surpassed previous summer peak record load of 236 set in July 2016. The winter peak record of 230 was set in December 2016.

(b)	The July 2016 summer peak load of 412 surpassed previous summer peak record load of 406 set in June 2016.

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(a)

Cheyenne Prairie, a 132 MW natural gas-fired power generation facility, was placed into commercial operation on October 1, 2014, to support 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 Wind Farm, a 29 MW wind farm, is operated by Colorado Electric. Colorado Electric has a 50% ownership interest in the wind farm and AltaGas owns the remaining 50%. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 MW of power from the wind farm.

(e)	Peak View Wind Farm achieved commercial operation on November 7, 2016.

(f)	Colorado Electric’s 40 MW combustion turbine achieved commercial operation on December 29, 2016.

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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%, 7% and 5% of our purchased power in 2017, 2016, and 2015, 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 AltaGas expiring on October 16, 2037, which provides up to 14.5 MW of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Farm;

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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, subject to WPSC and FERC approval in order to obtain regulatory treatment. The purchase price related to the option is $2.6 million per MW (65 MWs), adjusted for all depreciated capital additions since 2009, and reduced by depreciation (approximately $5 million per year) over a 35-year life beginning January 1, 2009. The net book value of Wygen I at December 31, 2017 was $69 million and if Wyoming Electric had exercised the purchase option at year-end 2017, the estimated purchase price would have been approximately $133 million;

•	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,

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•	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; and

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

•	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; and

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South Dakota Electric has an agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. 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:

•	South Dakota Electric has an agreement from January 1, 2017 through December 31, 2021 to provide 50 MW of energy to Cargill (assigned to Macquarie on January 3, 2018) during heavy and light load timing intervals.

(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 MAPP 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

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•	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 their share of the Wygen III generating facility for the life of the plant.

◦	Colorado Electric and AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric charges AltaGas for operations and maintenance for their share of the Busch Ranch Wind Farm.

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An annual adjustment clause which provides for the direct recovery of increased fuel and purchased power cost incurred to serve South Dakota customers. Additionally, the 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 $2 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 $2 million. South Dakota Electric retains the additional 30%. 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 annual Environmental Improvement Adjustment (EIA) tariff which recovers costs associated with generation plant environmental improvements. The EIA and TFA were suspended for a six-year period effective July

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•	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, symmetrical interest, 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.

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

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

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

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

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

(a)	Non-GAAP measure

(b)	Total MWh includes Other Uses, Losses or Generation, net, which is approximately 6%, 7%, and 8% 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)	Kansas and Arkansas have weather normalization mechanisms which mitigate the weather impact on gross margins.

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

(c)	To conform to the current year comparisons to normal, the 2016 utility variances compared to normal, as well as the 2016 combined variance compared to normal have been updated.

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

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(a)	Acquired through SourceGas

(b)	Arkansas return on rate base adjusted to remove current liabilities from rate case capital structure for comparison with other subsidiaries.

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

(d)	Total Nebraska 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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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 we have 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 is driven by the joint dispatch agreement Colorado Electric joined in 2017. See details of this agreement above in the Electric Utilities segment.

(c)	Under the 20-year economy energy PPA with the City of Gillette, effective September 2014, Black Hills Wyoming purchases energy on behalf of the City of Gillette and sells that energy to the City of Gillette.

•	Economy Energy PPA and other ancillary agreements

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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, and 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.

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•	Operating and Maintenance Services Agreement

◦

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 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 their share of the Wygen I generating facility over the life of the plant.

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•	South Dakota Electric for use at the 90 MW Neil Simpson II plant. This contract is for the life of the plant;

•	Wyoming Electric for use at the 95 MW Wygen II plant. 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. 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 new 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 717,000 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 237,000 square feet utilized by our Electric Utilities and Mining segments.

(a)	On January 26, 2017, South Dakota Electric’s contract was ratified with an expiration date of March 31, 2022.

(b)	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.

(c)	Kansas Gas completed a wage adjustment that was ratified on November 15, 2017.

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ITEM 1A.	RISK FACTORS

•	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, 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 27% 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, 2017, approximately 24% 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.

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•	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;

•	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 secure adequate 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 business. 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, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2017 and 2016 was reduced by $14 million and $9.6 million, respectively, attributable to this noncontrolling interest. 2013 includes $6.6 million after-tax expense relating to the settlement of interest rate swaps and write-off of deferred financing costs in conjunction with the prepayment of Black Hills Wyoming’s project financing.

(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. 2013 includes $20 million non-cash after-tax unrealized mark-to-market gains, respectively, related to certain interest rate swaps; 2013 also includes $7.6 million after-tax expense for a make-whole premium, write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt.

(e)	Discontinued operations in 2013 includes post-closing adjustments and operations relating to Enserco, sold in 2012.

(f)	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.

(g)	The decrease in 2017 is driven by the joint dispatch agreement Colorado Electric became a part of in 2017. See details of this agreement in Item 1. Business and Properties, Electric Utilities Segment in this Annual Report on Form 10-K.

(h)	Calculated based on Income (loss) from continuing operations available for common stock.

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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

•	Our three electric utilities achieved 1st quartile reliability ranking with 67 customer minutes of outage time (SAIDI) in 2017 compared to industry averages (IEEE 2017 1st quartile is less than 97 minutes);

•	Our power generation fleet achieved a forced outage factor of 5.04% for coal-fired plants, 1.42% for natural gas-fired turbines, 0.74% for natural gas-combined cycle power blocks and 0.17% for diesel plants in 2017, compared to an industry average* of 3.10%, 3.38%, 2.24% and 1.03%, respectively (*NERC GADS 2016 Data);

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Our power generation fleet availability was 89.82% for coal-fired plants, 95.70% for natural gas-fired turbines, 95.93% for natural gas-combined cycle power blocks, 99.53% for diesel-fired plants, and 94.06% for wind generation in 2017 while the industry averages** were 86.37%, 90.88%, 94.11%, 93.61 and 96.0% respectively (** NERC GADS 2016 data used for coal, natural gas-gas turbines, natural gas-combined cycles, and diesel plants; NERC GADS does not keep wind at this time; accordingly, wind average obtained from wind generation articles by manufacturer(s));

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•	Our safety TCIR of 1.3 compares to an industry average of 2.1+ and our DART rate of 0.8 compares to an industry average of 1.2+ (+ Bureau of Labor Statistics (BLS)-all utilities of all sizes - most recent industry averages are 2016); and

•	Our mine completed over five years with no MSHA reportable injuries and received an award from the State of Wyoming for eight years without a lost time incident.  The mine also received the State Mine Inspector’s Award for the fourth year in a row for operating as the safest small mine and received the Mine Safety and Health Administration’s Certificate of Achievement for No Lost Time Incidents.

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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 consumers 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 from continuing operations available for common stock 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. 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 which includes $28 million of tax expense from the revaluation of Corporate deferred taxes, as well as an additional $7.0 million of tax expense from the revaluation of deferred taxes that were originally recorded to AOCI.

(b)	Income from continuing operations available for common stock 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.

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

(d)

Income from continuing operations available for common stock for 2017, 2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $2.8 million, $30 million and $6.7 million, respectively and after-tax internal labor costs attributable to the SourceGas Acquisition of $0.5 million, $9.1 million and $3.0 million, respectively that otherwise would have been charged to other business segments.

(e)	Income from continuing operations available for common stock 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.

(f)	Loss from discontinued operations in 2017, 2016 and 2015 included non-cash after-tax impairments of crude oil and natural gas properties of $13 million, $67 million and $160 million, respectively. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(g)	Loss from discontinued operations in 2016 included a tax benefit of approximately $5.8 million recognized from additional percentage depletion deductions that are being claimed with respect to our oil and gas properties involving prior years.

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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 11% lower than normal compared to 13% lower than normal in 2016. Cooling degree days for the full year of 2017 were 14% higher than normal compared to 26% 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 megawatts 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. We expect a final decision from the CPUC in the second quarter of 2018 approving, conditioning, modifying or rejecting Colorado Electric’s recommended portfolio.

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On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision to increase annual revenue by $1.2 million. This application was denied by the CPUC on June 9, 2017. We subsequently filed an appeal of this decision with Denver County District Court on July 10, 2017. On October 4, 2017, the Company filed an Opening Brief. The Company filed a Reply Brief on November 22, 2017.  The matter is pending.

•	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.

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On December 15, 2017, Arkansas Gas filed a rate review application with the APSC requesting an annual increase in revenue of approximately $30 million. The annual increase is based on a return on equity of 10.2% and a capital structure of 45.3% debt and 54.7% equity. This rate review was driven by approximately $160 million of investments made since 2016 to replace, upgrade and maintain Arkansas Gas’ approximately 5,500 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implemented in the fourth quarter of 2018. We are reviewing the impact of tax reform as it applies to the filing.

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On November 17, 2017, Wyoming Gas requested rate review application with the WPSC requesting an annual increase in revenue of approximately $1.4 million for natural gas system improvements supporting its Northwest Wyoming customers. The annual increase is based on a return on equity of 10.2% and a capital structure of 46% debt and 54% equity. This rate review was driven by approximately $6 million of investments made since 2015 to replace, upgrade and maintain approximately 620 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implemented in mid-2018. We are reviewing the impact of tax reform as it applies to the filing.

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On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31, 2018; this application requests a continuation of the SSIR through 2022. We are reviewing the impact of tax reform as it applies to the filing.

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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.

•	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.

•	On July 21, 2017, S&P affirmed Black Hills’ credit rating at BBB rating and maintained a Stable outlook.

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On November 1, 2017, the BHC board of directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90 percent of our oil and gas properties. We have executed agreements to sell all our operated properties and have only non-operated assets with minimal value left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018. The results of our Oil and Gas segment are reflected in discontinued operations, other than certain general and administrative and interest costs which have been reallocated to our other segments. Oil and Gas segment assets and liabilities are classified as held for sale.

•	higher earnings at our Electric Utilities of $8.2 million driven primarily by returns on generation investments;

•	higher earnings at our Gas Utilities of approximately $20 million, which include earnings of $15 million from our acquired SourceGas utilities since the acquisition date of February 12, 2016;

•	tax benefits of approximately $5.1 million from the re-measurement of uncertain tax positions’ liability predicated on an agreement reached with IRS Appeals;

•	Increased corporate expenses which included approximately $30 million of after-tax incremental acquisition and transition costs related to SourceGas;

•	Lower earnings at our Power Generation segment due to net income attributable to noncontrolling interests of $9.6 million;

•	Lower earnings at our Mining segment due to an extended 2016 outage at the Wyodak plant.

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In our Electric Utilities service territories, mild winter weather in 2016 partially offset a hotter than normal summer. Heating degree days were 2% lower than the prior year and 13% lower than normal. Offsetting this decrease was weather related demand during the peak summer months. Cooling degree days for the full year of 2016 were 9% higher than the same period in the prior year and 26% higher than normal.

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On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million, 40 MW natural gas-fired combustion turbine. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity.

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On November 8, 2016, Colorado Electric completed the purchase of Peak View, a $109 million, 60 MW Wind Project located near Colorado Electric's Busch Ranch Wind Farm. Peak View achieved commercial operation on November 7, 2016 and was purchased through progress payments throughout 2016 under a commission approved third-party build- transfer and settlement agreement. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. The Commission’s settlement agreement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments, Renewable Energy Standard Surcharge and Transmission Cost Adjustment for 10 years, after which Colorado Electric can propose base rate recovery.

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During the first quarter of 2016, South Dakota Electric commenced construction of the $54 million, 230-kV, 144 mile-long transmission line that connects the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. Recovery is concurrent through the FERC transmission tariff. 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 in May of 2017.

•	On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing. See additional information below under Corporate activities.

•	Gas Utilities were unfavorably impacted by milder weather in 2016 compared to 2015. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2015. Heating degree days for the full year in 2016 were 11% less than normal and 1% less than the same period in 2015.

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Black Hills Colorado IPP owns and operates a 200 MW, combined cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP for $216 million. FERC approval of the sale was received on March 29, 2016. Proceeds from the sale were used to pay down short-term debt. Black Hills Electric Generation continues to be the majority owner and operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric.

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In 2016, we implemented a $750 million, unsecured CP Program that is backstopped by our Revolving Credit Facility, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extended the term through August 9, 2021 and we entered into a new $500 million term loan expiring August 9, 2019. We completed the permanent financing for the SourceGas Acquisition. In addition to the net proceeds of $536 million from our November 2015 equity issuances, we completed the Acquisition financing with $546 million of net proceeds from our January 2016 debt offering. We also refinanced the long-term debt assumed with the SourceGas Acquisition primarily through $693 million of net proceeds from our August 19, 2016 debt offerings. In addition to our debt refinancings, we issued 1.97 million shares of common stock for approximately $119 million through our ATM equity offering program, and sold a 49.9% noncontrolling interest in Black Hills Colorado IPP for $216 million. On June 7, 2016, we issued a $29 million, declining balance five-year term loan maturing June 7, 2021, to finance the early termination of a gas supply agreement. See Footnotes 6 and 7 of the Notes to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information relating to our long-term debt and notes payable.

•	On December 9, 2016, Moody’s issued a Baa2 rating with a Stable outlook, which reflects the higher debt leverage resulting from the incremental debt used to fund the SourceGas Acquisition.

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During the first quarter of 2016, we reached an agreement in principle with IRS Appeals with respect to our liability for unrecognized tax benefits attributable to the like-kind exchange effectuated in connection with the 2008 IPP Transaction and the 2008 Aquila Transaction. This agreement resulted in a tax benefit of approximately $5.1 million in the first quarter of 2016. See Note 15 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional details on this agreement.

•	On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in long-term debt at closing.

•	On February 12, 2016, S&P affirmed the BHC credit rating of BBB and maintained a stable outlook after our acquisition of SourceGas, reflecting their expectation that management will continue to focus on the core utility operations while maintaining an excellent business risk profile following the acquisition.

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•	On February 12, 2016, Fitch affirmed the BHC credit rating of BBB+ and maintained a negative outlook after our acquisition of SourceGas, which reflects the initial increased leverage associated with the SourceGas Acquisition.

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On January 20, 2016, we executed a 10-year, $150 million notional, forward starting pay fixed interest rate swap at an all-in interest rate of 2.09%, and on October 2, 2015, we executed a 10-year, $250 million notional forward starting pay fixed interest rate swap at an all-in rate of 2.29%, to hedge the risks of interest rate movement between the hedge dates and pricing date for long-term debt refinancings occurring in August 2016. On August 19, 2016, we settled and terminated these interest rate swaps for a loss of $29 million. The loss recorded in AOCI is being amortized over the 10-year life of the associated debt.

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(c)	2015 reflects planned outages at Neil Simpson II, Wygen II and Wygen III.

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

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(a)	Wygen I experienced an unplanned outage in 2016 and a planned outage in 2017.

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(a)	Increase in overburden was due to relocating mining operations to areas of the mine with higher overburden.

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(a)

Represents the revaluation of deferred tax balances not attributable to our operating segments or discontinued operations due to the decrease in the statutory Federal income tax rate as a result of the TCJA. Deferred taxes originally recorded to AOCI were also revalued to reflect the decrease in the statutory Federal income tax rate. See Notes 15 and 16 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more details.

(b)	Acquisition and transition costs attributed to SourceGas acquisition including incremental transaction costs consisting of professional fees, financing fees, employee-related expenses and other miscellaneous costs and internal labor costs attributable to the acquisition that would otherwise have been charged to the other business segments.

(c)

Reallocated indirect corporate operating costs and interest expenses previously allocated to BHEP which are not reclassified to discontinued operations in accordance with GAAP as they have a continuing impact on the Company. After-tax 2017 operating expenses of approximately $2.0 million were reallocated to our other business segments in 2017. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for more details.

(d)	We recognized a $4.4 million tax benefit during 2016 as a result of an agreement reached with IRS Appeals relating to the release of the reserve for after-tax interest expense previously accrued with respect to the liability for uncertain tax positions involving a like-kind exchange transaction from 2008.

•	Tax expense of $35 million not attributable to our operating segments reflecting the revaluation of deferred tax balances, including those originally recorded in AOCI, as a result of the TCJA;

•	A decrease in 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.

•	An increase in acquisition and transition expenses of approximately $29 million driven by higher external costs and an increase in internal labor attributed to the SourceGas acquisition;

•	An increase in allocated expenses from discontinued operations;

•	An increase of approximately $4.4 million in tax benefits; and

•	A decrease in other corporate expenses.

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(a)	Net of hedge settlement gains/losses

(a)	Full cost accounting was no longer applicable at November 1, 2017 and depletion was not recorded after November 1, 2017. The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. See Note 22 of Notes to the Consolidated Financial Statements included in this Annual Report filed on Form 10-K.

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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)	Averages for the Revolving Credit Facility are for the first 29 days of the year after which all borrowings were through the CP Program.

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•	Remarketing the junior subordinated notes maturing in 2018;

•	Evaluating an extension of our Revolving Credit Facility and CP program; and

•	Evaluating refinancing options for term loan and short-term borrowings under our Revolving Credit Facility and CP program.

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•	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 a prior year interest rate swap settlement;

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

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

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

•	The prior year’s 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;

•	Distributions to noncontrolling interests increased by $8.8 million compared to prior year; and

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

•	Cash earnings (income from continuing operations plus non-cash adjustments) were $62 million higher than prior year.

•	Net outflow from operating assets and liabilities was $59 million higher than prior year, primarily attributable to:

•	Cash outflows increased by approximately $66 million compared to the prior year as a result of higher materials, supplies and fuel and higher accounts receivable partially due to colder weather and higher natural gas volumes sold;

•	Cash outflows increased by approximately $34 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 $42 million as a result of changes in accounts payable and accrued liabilities driven primarily by acquisition and transition costs, partially offset by an increase in accrued interest;

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

•	Cash outflows increased by $4.0 million due to pension contributions;

•	Cash outflows decreased approximately $8.4 million for other operating activities compared to the prior year; and

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•	Cash inflows decreased approximately $83 million due to operating activities of discontinued operations.

•	Cash outflows of $1.1 billion for the acquisition of SourceGas, net of $11 million cash received from a working capital adjustment and $760 million of long term debt assumed (see Note 2 in Item 8 of Part II of this Annual Report on Form 10-K);

•	In 2016, we had higher capital expenditures of $189 million primarily at our Electric Utilities and Gas Utilities, driven by 2016 wind and natural gas generation additions at our Electric Utilities, and additional capital at our acquired SourceGas Utilities;

•	In 2015, we acquired the net assets of two natural gas utilities for $22 million; and

•	Cash outflows decreased approximately $179 million due to investing activities of discontinued operations.

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

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Long-term borrowings increased due to the $693 million of net proceeds from our August 19, 2016 public debt offering used to refinance the debt assumed in the SourceGas Acquisition, the $500 million of proceeds from our new term loan on August 9, 2016 used to pay off existing debt, the $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, compared to proceeds of $300 million from long-term borrowings from a term loan in the prior year;

•	Payments on long term borrowings increased due to payments made in the current year to refinance the $760 million of long-term debt assumed in the SourceGas Acquisition and $404 million of current year payments made on term loans compared to the payment of $275 million made as part of a term-loan refinancing in the prior year;

•	In 2015, we received net proceeds of $290 million from the issuance of our RSNs;

•	Proceeds of $120 million primarily from issuing common stock under our ATM equity offering program. 2015 included net proceeds from common stock issuances of $246 million;

•	Net short-term borrowings under the revolving credit facility for the year ended December 31, 2016 were $18 million higher than the prior year primarily due to higher working capital requirements in the current year;

•	Distributions to noncontrolling interests of $9.6 million;

•	Cash outflows for other financing activities increased by approximately $14 million driven primarily by approximately $22 million of financing costs and make whole payments made in 2016 compared to $7 million of bridge facility fees paid in 2015; and

•	Cash dividends on common stock of $88 million were paid in 2016 compared to $73 million paid in 2015.

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

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(a)	On July 21, 2017, S&P affirmed BBB rating and maintained a Stable outlook.

(b)	On December 12, 2017, Moody's affirmed our Baa2 rating and maintained a Stable outlook.

(c)	On October 4, 2017, Fitch affirmed BBB+ rating and maintained a Stable outlook.

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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 based on a mid-year retirement date for long-term debt expiring during the identified period and are not included within the long-term debt balances presented: $127 million in 2018, $122 million in 2019, $113 million in 2020, $101 million in 2021 and $101 million in 2022. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2017.

(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 2017 and price assumptions using existing prices at December 31, 2017. Our transmission obligations are based on filed tariffs as of December 31, 2017.

(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 Plans and payments to employees for the Non-Pension Defined Benefit Postretirement Healthcare Plans and the Supplemental Non-Qualified Defined Benefit Plans through the year 2027.

(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, 2017. 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.

•	Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain of our gas-fired generation assets; and

•	Interest rate risk associated with our variable rate debt as described in Notes 6 and 7 of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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(a)	Excludes unamortized premium or discount.

(b)	The average interest rates do not include the effect of interest rate swaps.

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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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(a)	Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.

(a)	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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The commodity contracts for the Electric and Gas Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchanged-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For over-the-counter swaps and option Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market pricing data. In addition, the fair value for the over-the-counter swaps and option derivatives include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

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Interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. We have no interest rate swaps as of December 31, 2017.

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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.

(d)

The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018.

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(a)	The plant acquisition adjustment is included in rate base and is being recovered with 13 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 $14 million.

(a)	Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $6.1 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 MAPP 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. We retain responsibility for plant operations. Our Mining subsidiary supplies coal to Wygen III for the life of the plant.

•	Colorado Electric owns 50% of the Busch Ranch Wind Farm while AltaGas owns the remaining undivided ownership interest and is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm for the life of the facility. We retain responsibility for operations of the wind farm.

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•	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. We retain responsibility for plant operations.

(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.

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

(b)	SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2.

(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.

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(a)	The effective tax rate is lower in 2017 resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017.

(b)	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).

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

(a)	Includes interest allocations in 2017, 2016 and 2015 of approximately $4.9 million, $5.6 million and $3.4 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 $1.7 million and $2.3 million as of December 31, 2017 and December 31, 2016, respectively.

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•	$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017.

•	$95 million, 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019.

•	$340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875%.

•	Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition;

•	Repay the $95 million, 3.98% senior secured notes assumed in the SourceGas Acquisition;

•	Repay $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition;

•	Pay down $100 million of the $500 million three-year unsecured term loan discussed below;

•	Payment of $29 million for the settlement of $400 million notional interest rate swap; and

•	Remainder was used for general corporate purposes.

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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, 2017, the restricted net assets at our Electric and Gas Utilities were approximately $257 million.

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(a)	Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas.

(b)	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.

(c)	The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming.

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•	Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain of our gas-fired generation assets; and

•	Interest rate risk associated with our variable rate debt.

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(a)	Term reflects the maximum forward period hedged.

(b)	Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions.

(c)	As of December 31, 2017, 1,650,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.

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

(a)	The $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.

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

(b)	Notes payable consist of commercial paper borrowings in 2017 and borrowings on our Revolving Credit Facility in 2016. 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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if the “Applicable Market Value” (AMV) of the Company’s common stock, which is the average volume-weighted average price of the Company’s common stock for the trading days during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the forward purchase contract settlement date, equals or exceeds $47.2938, 1.0572 shares of the Company’s common stock per Equity Unit;

•	if the AMV is less than $47.2938 but greater than $40.25, a number of shares of the Company’s common stock having a value, based on the AMV, equal to $50; and

•	if the AMV is less than or equal to $40.25, 1.2422 shares of the Company’s common stock.

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(a)	The grant date fair values for the performance shares granted in 2017, 2016 and 2015 were determined by Monte Carlo simulation using a blended volatility of 23%, 24% and 21%, 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)	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)	The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $309 million. Due to the regulatory construct, approximately $301 million of the revaluation was reclassified to a regulatory liability.

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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.

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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)	Increase from 2016 is primarily the result of a decrease in the discount rate.

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(a)	Assets of VEBAs and Grantor Trust.

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(a)	The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2017 and 2016 represents that obligation for the five postretirement plans maintained by BHC.

(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 merged Black Hills Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs.

(b)	The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost.

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(a)	The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas.

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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 that expires 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.

•	Colorado Electric’s REPA with AltaGas expiring October 16, 2037, provides up to 14.5 MW of wind energy from the Busch Ranch Wind Farm in which Colorado Electric owns a 50% undivided ownership interest.

(a)	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.

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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, 2023. 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 from January 1, 2017 through December 31, 2021 to provide 50 MW of energy to Cargill (assigned to Macquarie on January 3, 2018) 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.

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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

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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 143,441 full value awards outstanding as of December 31, 2017, 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, 267,284 shares of unvested restricted stock were outstanding as of December 31, 2017, 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

(a)	Represents allowance balances added with the SourceGas acquisition.

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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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