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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

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•	Black Hills Energy South Dakota Electric - includes all Black Hills Power utility operations in South Dakota, Wyoming and Montana.

•	Black Hills Energy Wyoming Electric - includes all Cheyenne Light electric utility operations.

•	Black Hills Energy Colorado Electric - includes all Colorado Electric utility operations.

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•	Black Hills Energy Arkansas Gas - includes the acquired SourceGas utility Black Hills Energy Arkansas operations.

•	Black Hills Energy Colorado Gas - includes Black Hills Energy Colorado Gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Colorado operations and RMNG operations.

•	Black Hills Energy Nebraska Gas - includes Black Hills Energy Nebraska gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Nebraska operations.

•	Black Hills Energy Iowa Gas - includes Black Hills Energy Iowa gas utility operations.

•	Black Hills Energy Kansas Gas - includes Black Hills Energy Kansas gas utility operations.

•	Black Hills Energy Wyoming Gas - includes Cheyenne Light’s natural gas utility operations, as well as the acquired SourceGas utility Black Hills Gas Distribution’s Wyoming operations.

•	Black Hills Energy Services - includes the acquired SourceGas Utility Black Hills Energy Services operations.

(a)	Both 2016 summer and winter peaks are records set in July and December, respectively, replacing summer and winter record peaks set in July and December of 2015.

(b)	New summer peak load for Colorado Electric achieved in July 2016, replacing the previous all-time summer peak of 406 set in June 2016, and of 400 set in June 2012.

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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 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 newly constructed LM 6000, which achieved commercial operation on December 29, 2016.

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(a)	Decrease is driven by lower 2016 natural gas costs than the prior year.

(b)	Decrease is due to combination of lower fuel costs in 2016 and the efficiencies at which the diesel units performed compared to the prior year.

(a)	Wind represents approximately 7% of our purchased power in 2016, and approximately 5% of our purchased power in 2015 and 2014.

•	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 adjusted for capital additions and reduced by depreciation over a 35-year life beginning January 1, 2009 (approximately $5 million per year);

•	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 inter-company agreement, Wyoming Electric sells 50% of the facility’s output to South Dakota Electric;

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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 inter-company 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

•	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. 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:

(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 to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids.

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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.

(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.

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(a)	Increase is driven primarily by load growth supporting data centers in Cheyenne, Wyoming.

(b)	Decrease is due to lower commodity prices that reduced gross sales.

(c)	Other revenue primarily consists of transmission revenue.

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(a)	Natural gas-fired generation from Cheyenne Prairie increased in 2016 primarily due to lower coal fired generation driven by 2016 outages at the coal-fired Wyodak plant.

(b)	Neil Simpson I was retired on March 21, 2014.

(c)	Increase in 2016 was due to a 2015 planned annual outage at Wygen II.

(d)	Cheyenne Prairie was placed into commercial service on October 1, 2014.

(e)	Lower commodity prices drove an increase in generation and a corresponding decrease in purchased power.

(f)	Increase in 2016 is due to the addition of the Peak View Wind Project in November 2016.

(g)	Includes wind power of 269,552 MWh, 227,396 MWh and 224,229 MWh in 2016, 2015 and 2014, respectively.

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(a)	Year over year increases since 2014 are driven by new load supporting data centers in Cheyenne, Wyoming.

(b)	Decrease in 2015 is primarily due to the expiration in March 2015 of a 5 MW unit contingent capacity contract with MEAN.

(c)	Decrease in 2016 is driven by weaker market conditions.

(d)	Includes Company uses, line losses, test energy and excess exchange production.

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

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(a)	Arkansas has a weather normalization mechanism in effect during the months of November through April for those customers with residential and business rate schedules. The weather normalization mechanism in Arkansas only uses one location to calculate the weather, minimizing, but not eliminating weather impact.

(b)	Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins, using multiple locations.

(c)	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.

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

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(a)	Increased transportation in Nebraska and parts of Wyoming is due to Choice Gas Program customers acquired in the SourceGas Acquisition.

(b)	Intercompany volumes from RMNG’s transmission system to Black Hills Gas Distribution are not included.

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(a)	Increased transportation in Nebraska and parts of Wyoming is due to Choice Gas Program customers acquired in the SourceGas Acquisition.

(b)	Change in customers is due to classification change to Commercial billing in 2015 based on customer’s business type.

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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 70% of off-system power marketing operating income. 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 vegetation management recovery mechanism that allows for recovery of and a return on prudently-incurred vegetation management costs.

•	An approved annual Environmental Improvement Cost Recovery Adjustment tariff which recovers costs associated with generation plant environmental improvements.

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

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•	An annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. As of October 1, 2014, the annual cost adjustment allows for recovery of 85% of coal and coal-related costs, and recovery of 95% of purchased power costs, transmission, and natural gas costs.

•	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 LM6000 generating unit 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.

(a)

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 and normal increases in operating expenses. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air Clean Jobs Act construction financing rider. 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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(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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(a)

In February 2016, Arkansas Gas implemented new base rates resulting in a revenue increase of $8.0 million. The APSC modified a stipulation reached between the APSC Staff and all intervenors except the Attorney General and Arkansas Gas in its order issued on January 28, 2016. The modified stipulation revised the capital structure to 52% debt and 48% equity and also limited recovery of portions of cost related to incentive compensation.

(b)	On November 15, 2016, Arkansas Gas filed for recovery of Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism, approved on October 15, 2015, with rates effective January 1, 2017.

(c)	On January 3, 2017 Arkansas Gas filed for recovery of $1.5 million related to projects for the replacement of eligible mains (MRP) and the recovery of $0.2 million related to projects for the relocation of certain at risk meters (ARMRP). Pursuant to the Arkansas Gas Tariff, the filed rates go into effect on the date of the filing.

(d)	On November 3, 2016, RMNG filed with the CPUC requesting recovery of $2.9 million, which includes $1.2 million of new revenue related to system safety and integrity expenditures on projects for the period of 2014 through 2017. This SSIR request was approved by the CPUC in December 2016, and went into effect on January 1, 2017.

(e)	On October 3, 2016, Nebraska Gas Dist. filed with the NPSC requesting recovery of $6.5 million, which includes $1.7 million of new revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2017, and will go into effect on February 1, 2017.

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Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a 2% 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)	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.

•	Operating and Maintenance Services Agreement

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In conjunction with the sale of the noncontrolling interest on April 14, 2016, an operating and maintenance services agreement was entered into between Black Hills Electric Generation and Black Hills Colorado IPP.  This agreement sets forth the obligations and responsibilities of Black Hills Electric Generation as the operator of the generating facility owned by Black Hills Colorado IPP.    This agreement is in effect from the date of the noncontrolling interest purchase and remains effective as long as the operator or one of its affiliates is responsible for managing the generating facilities in accordance with the noncontrolling interest agreement, or until termination by owner or operator.

•	Shared Services Agreements

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

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

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•	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 at the end of December 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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(a)	Revisions to prior year estimates is primarily due to the impact of lower prices on the economics of the San Juan reserves.

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(a)	Nine Mancos wells were completed and placed on production in 2015.

(b)	Revisions to previous estimates were primarily driven by low commodity prices.

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(a)	Revisions to prior year were primarily driven by commodity prices.

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(a)

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. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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(a)	The majority of these wells are non-operated wells.

(a)	The majority of these wells are non-operated wells.

(a)	The majority of these wells are non-operated wells.

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(a)

Approximately 3% (14,081 gross and 3,406 net acres), 3% (22,834 gross and 4,405 net acres) and 7% (56,265 gross and 9,211 net acres) of our undeveloped acreage could expire in 2017, 2018 and 2019, respectively, if production is not established on the leases or further action is not taken to extend the associated lease terms. Decisions on extending leases are based on expected exploration or development potential under the prevailing economic conditions.

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•	In Rapid City, South Dakota, we own an eight-story, 66,000 square foot office building where our corporate headquarters is located, an office building consisting of approximately 36,000 square feet, and a service center, warehouse building and shop with approximately 65,000 square feet.

•	In Rapid City, South Dakota, we have a new 220,000 square foot corporate headquarters building under construction. Construction is expected to be completed in the fourth quarter of 2017.

•	In Pueblo, Colorado, we own a building of approximately 46,600 square feet used for a service center and approximately 25,700 square feet used for a warehouse.

•	In Cheyenne, Wyoming, we own an operations center with approximately 25,000 square feet, and in Casper Wyoming, we own an 18,000 square foot distribution center.

•	In Papillion, Nebraska, we own an office building consisting of approximately 36,600 square feet; in Albion, Nebraska, we own an operations center with approximately 26,000 square feet; and in Kearney, Nebraska, we own an operations center with approximately 21,000 square feet.

•	In Fayetteville, Arkansas, we own an operations center with approximately 36,000 square feet.

•	In Arkansas, Nebraska, Iowa, Colorado, Kansas and Wyoming we own various office, service center, storage, shop and warehouse space totaling over 666,000 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 117,000 square feet utilized by our Electric Utilities and Mining segments.

•	Approximately 8,800 square feet for an operations and customer call center and 9,100 square feet of office space in Rapid City, South Dakota;

•	Approximately 37,600 square feet for a customer call and operations center in Lincoln, Nebraska, and approximately 12,000 square feet for an operations center in Norfolk, Nebraska;

•	Approximately 47,400 square feet of office space in Denver, Colorado, of which we sublease approximately 10,100 square feet to a third party, and approximately 27,000 square feet of office space in Golden, Colorado, which is the former SourceGas Corporate headquarters;

•	Approximately 35,000 square feet for office space and customer call center in Fayetteville, Arkansas;

•	Approximately 204,000 square feet of various office, service center and warehouse space leased by the Gas Utilities; and

•	Other offices and warehouse facilities located within our service areas.

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

(b)	Negotiations for Nebraska Gas started in January 2017, with an expected ratification in March 2017. We do not anticipate any issues with the ratification.

(c)	In the 2016 negotiations with the CWA 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.

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ITEM 1A.	RISK FACTORS

•	Our inability to obtain required governmental permits and approvals or the imposition of adverse conditions upon the approval of any acquisition;

•	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 successfully integrate any businesses we acquire;

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

•	Our inability to negotiate acceptable acquisition, 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, our oil and gas 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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•	Operational limitations imposed by environmental and other regulatory requirements;

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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;

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

•	Our ability to transition and replace our retirement-eligible utility employees. At December 31, 2016, approximately 27% of our Electric Utilities and Gas Utilities employees were eligible for regular or early retirement;

•	Inability to recruit and retain skilled technical labor;

•	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;

•	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;

•	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;

•	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; and

•	Labor relations. Approximately 27% of our employees are represented by a total of seven collective bargaining agreements.

•	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;

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•	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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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)	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)

2016 includes non-cash after-tax impairment charges to our crude oil and natural gas properties of $67 million. 2015 includes non-cash after-tax ceiling test impairment charges to our 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 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K). 2012 includes a non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties of $32 million offset by an after-tax gain on sale of $49 million related to our Williston Basin assets.

(c)

On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million 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)

2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $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 and 2012 include $20 million and $1.2 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, while 2012 includes an after-tax make-whole provision of $4.6 million for early redemption of our $225 million notes.

(e)	Discontinued operations in 2013 and 2012 include 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)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility results have been reclassified from the Electric Utilities segment to the Gas Utilities segment in the amounts of $1.7 million, $2.3 million, $3.1 million and $0.5 million for the years ending December 31, 2015, 2014, 2013 and 2012 respectively. Due to this reclassification, there also exists an intersegment elimination of $0.2 million that has been moved to “Corporate and intersegment eliminations” for the period ended December 31, 2015.

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

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

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•	Our three electric utilities achieved 1st quartile reliability ranking with 64 customer minutes of outage time (SAIDI) in 2016 compared to industry averages (IEEE 2016 1st quartile is less than 81 minutes);

•	Our JD Power Customer Satisfaction Survey indicated our Electric and Gas Utilities were favorable to our peers in the Midwest;

•	Our power generation fleet achieved a forced outage factor of 3.27% for coal fired plants, 0.76% for natural gas plants, and 0.00% for diesel plants in 2016, compared to an industry average* of 4.61%, 4.41%, and 2.18%, respectively (*NERC GADS 2015 Data);

•	Our power generation fleet availability was 94.41% for coal fired plants, 96.56% for natural gas fired plants, 98.92% for diesel fired plants, and 99.20% for wind generation in 2016 while the industry averages** were 85.29%, 89.65%, 94.59% respectively (**NERC GADS 2015 data was used for coal, natural gas and diesel; data is not currently kept for wind);

•	Our safety TCIR of 1.7 compares well to an industry average of 2.2+ and our DART rate of 0.6 compares to an industry average of 1.2+ (+ Bureau of Labor Statistics (BLS)-all utilities of all sizes - most recent industry averages are 2015);

•	Our OSHA TCIR rate during construction of our generating facilities is also significantly better than industry average with a TCIR rate of 3.1 during the 2016 construction of the Pueblo LM 6000 compared to an industry average of 4.4 for natural-gas fired plants.

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Our mine completed five years with favorable MSHA safety results compared to other mines located in the Powder River Basin and received an award from the State of Wyoming for seven years without a lost time accident.  The mine also received the State Mine Inspector’s Award for the third 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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•	Since the 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, than if the power was purchased from the open market through wholesale contracts that are re-priced over time;

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

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

•	The lower risk profile of rate based generation assets may enhance credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

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Colorado legislative mandates apply to our electric utilities segment regarding the use of renewable energy. Therefore, we pursue cost‑effective initiatives that allow us to meet our renewable energy requirements. Where permitted, we seek to construct renewable generation resources as rate base assets, which helps mitigate the long-term customer rate impact of adding renewable energy supplies. For example, the Busch Ranch Wind Farm, a 29 MW wind farm project, was completed in the fourth quarter of 2012, as part of our plan to meet Colorado’s Renewable Energy Standard. We had also previously submitted requests for additional renewable energy supplies in 2014 for our Colorado Electric utility to help meet the renewable mandate. On October 21, 2015, we received approval from the Colorado Public Utilities Commission to purchase the $109 million, 60 MW Peak View Wind Project, under the terms of a build/transfer agreement with a third party developer. This wind project commenced commercial operation in November 2016;

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In states such as South Dakota and Wyoming that currently have no legislative mandate on the use of renewable energy, we have proactively integrated cost-effective renewable energy into our generation supply based upon our expectation that there will be mandatory renewable energy standards in the future or other standards, such as those established by the CPP. For example, under two 20-year power purchase agreements, we purchase a total of 60 MW of energy from wind farms located near Cheyenne, Wyoming, for use at our South Dakota Electric and Wyoming Electric subsidiaries; and

•	In all states in which we conduct electric utility operations, we are exploring other cost-effective potential biomass, solar and wind energy projects, particularly wind generation sites located near our utility service territories.

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(a)

Net income available for common stock for 2016 included a net tax benefit of approximately $3.1 million for the following items: at the Electric Utilities, a $2.1 million benefit related to production tax credits associated with the Peak View Wind Project being placed into service and flow through treatment of a treasury grant related to the Busch Ranch Wind Project; at the Gas Utilities, a tax benefit of approximately $2.2 million related to favorable flow through adjustments; and, various other items netting to $1.2 million of tax expense that predominantly affected Corporate.

(b)	On April 14, 2016, BHEG sold a 49.9% interest in Black Hills Colorado IPP. Net income available for common stock for 2016 was reduced by $9.6 million attributable to this noncontrolling interest.

(c)	Net income (loss) available for common stock for 2016 and 2015 included non-cash after-tax impairments of our crude oil and natural gas properties of $67 million and $160 million. See Note 13 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(d)	Net income (loss) available for common stock for 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.

(e)	Net income (loss) available for common stock for 2016 and 2015 include incremental SourceGas Acquisition costs, after-tax of $30 million and $6.7 million and 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 business segments.

(f)	Net income (loss) 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.

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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 will connect 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 is expected to be placed in service in the first half of 2017.

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•	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 10% less than normal and 1% less than the same period in 2015.

•	During the third quarter of 2016, the Company withdrew its Cost of Service Gas applications in Wyoming, Iowa, Kansas and South Dakota. In consideration of the July 2016 denial of the application from the NPSC and the April 2016 dismissal of its application from the CPUC, the Company is re-evaluating its Cost of Service Gas regulatory approval strategy.

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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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Our Oil and Gas segment was impacted by lower net hedged prices received for crude oil and natural gas for the year ended December 31, 2016 compared to the same period in 2015. The average hedged price received for natural gas decreased by 24% for the year ended December 31, 2016 compared to the same period in 2015. The average hedged price received for oil decreased by 6% for the year ended December 31, 2016 compared to the same period in 2015. Oil and Gas production volumes decreased 6% for the year ended December 31, 2016 compared to the same period in 2015 as production was limited to meeting minimum daily quantity contractual gas processing requirements in the Piceance.

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We review the carrying value of our natural gas and crude oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling test impairment charge in each quarter of 2016 totaling $92 million for the year ended December 31, 2016. We also recorded a $14 million impairment of other Oil and Gas depreciable properties not included in our full cost pool during the second quarter of 2016 as we advanced our strategy to divest non-core oil and gas assets. In 2016, we sold non-core assets for total proceeds of $11 million.

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On March 18, 2016, we implemented an ATM equity offering program allowing us to sell shares of our common stock with an aggregate value of up to $200 million. The shares may be offered from time to time pursuant to a sales agreement dated March 18, 2016. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. Through December 31, 2016, we have sold and issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million, net of $1.2 million in commissions.

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•

On December 22, 2016, we implemented a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. We did not borrow under the CP Program in 2016 and do not have any notes outstanding as of December 31, 2016.

•	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.

•	On August 19, 2016, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% 10-year senior notes due January 15, 2027 and $300 million of 4.20% 30-year senior notes due September 15, 2046. The proceeds of the notes were used for the following:

◦	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 the remaining $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 swaps; and

◦	Remainder was used for general corporate purposes.

•	On August 9, 2016, we entered into a $500 million, three-year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan were used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017.

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On August 9, 2016, 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, with two, one-year extension options (subject to consent from the lenders). The facility includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility up to $1 billion. Borrowings continue to be available under a base rate or various Eurodollar rate options, which are substantially the same as the former agreement.

•	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.

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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. We funded the majority of the SourceGas Transaction with the following financings:

•	On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consists of $300 million of 3.95%, 10-year senior notes due 2026, and $250 million of 2.50%, 3-year senior notes due 2019. Net proceeds after discounts and fees were approximately $546 million; and

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•	On November 23, 2015, we completed the offerings of common stock and equity units. We issued 6.325 million shares of common stock for net proceeds of $246 million and 5.98 million equity units for net proceeds of approximately $290 million.

•	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.

•	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.

•	In our Electric Utilities service territories, mild winter weather in 2015 offset a hotter than normal summer. Heating degree days were 11% lower than the prior year and 10% lower than normal. Offsetting this was weather related demand during the peak summer months. Cooling degree days for the full year of 2015 were 32% higher than the same period in the prior year and 16% higher than normal.

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Construction commenced in the second quarter of 2015 on Colorado Electric’s $63 million 40 MW natural gas-fired combustion turbine. As of December 31, 2015, approximately $35 million was expended Construction riders related to the project increased gross margins by approximately $1.9 million for the year ended December 31, 2015. This turbine was completed in and placed into service in December 2016.

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On July 23, 2015, South Dakota Electric received approval from the WPSC for a CPCN to construct the Wyoming portion of a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota. South Dakota Electric received approval on November 6, 2014 from the SDPUC for a permit to construct the South Dakota portion. Construction commenced in the first quarter of 2016, and the project is expected to be placed in service in the first half of 2017.

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On June 23, 2015, Colorado Electric filed for a CPCN with the CPUC to acquire the planned 60 MW Peak View Wind Project, to be located near Colorado Electric's Busch Ranch Wind Farm. This renewable energy project was originally submitted in response to Colorado Electric's all-source generation request on May 5, 2014. On October 21, 2015, the Commission approved a build transfer proposal and settlement agreement. The settlement provides for recovery of the costs of the project through Colorado Electric’s Electric Cost Adjustments and Renewable Energy Standard Surcharge for 10 years, after which Colorado Electric can propose base rate recovery. Colorado Electric will be required to make an annual comparison of the cost of the renewable energy generated by the facility against the bid cost of a PPA from the same facility. Colorado Electric purchased the project from a third-party for approximately $109 million through progress payments throughout 2016, with ownership transfer occurring on November 7, 2016.

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On March 16, 2015, we announced plans to build a new corporate headquarters in Rapid City, South Dakota that will consolidate our approximately 500 employees in Rapid City from five locations into one. The investment in the new corporate headquarters will be approximately $70 million and will support all our businesses. The cost of the facility will replace existing expenses associated with our current facilities throughout Rapid City. Construction began in September 2015 with completion expected in the fall of 2017.

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On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for South Dakota Electric of $6.9 million. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides South Dakota Electric a return on its investment in Cheyenne Prairie and associated infrastructure, and provides recovery of its share of operating expenses for this natural gas-fired facility. South Dakota Electric implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. Final rates were approved on April 1, 2015, effective October 1, 2014.

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In January 2015, Colorado Electric implemented new rates in accordance with the CPUC approval received on December 19, 2014 for an annual electric revenue increase of $3.1 million. The approval also allowed a 9.83% return on equity and a capital structure of 49.83% equity and 50.17% debt, as well as approving implementation of a construction financing rider. This approval allows Colorado Electric to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The implementation of the rider allows Colorado Electric to recover a return on the construction costs for a $63 million natural gas-fired combustion turbine that was constructed in 2015 and 2016 to replace the retired W.N. Clark power plant.

•	Gas Utilities were unfavorably impacted by milder weather in 2015 compared to 2014. Our service territories reported warmer than normal winter weather as measured by heating degree days, compared to the 30-year average, and compared to 2014. Heating degree days for the full year in 2015 were 8% less than normal and 13% less than the same period in 2014.

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On July 1, 2015, we completed the acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc. The utility and pipeline assets were acquired for approximately $17 million, and operate as subsidiaries of Wyoming Electric. The acquired system serves approximately 6,700 customers, in Cody, Ralston, and Meeteetse, Wyoming. The pipeline acquisition includes a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory.

•	In January 2015, Kansas Gas implemented new base rates in accordance with the rate request approval received on December 16, 2014 from the KCC to increase base rates by $5.2 million. This increase in base rates allows Kansas Gas to recover infrastructure and increased operating costs. The approval was a Global Settlement and did not stipulate return on equity and capital structure.

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Our Oil and Gas segment was impacted by lower commodity prices for crude oil and natural gas for the year ended December 31, 2015 compared to the same period in 2014. The average hedged price received for natural gas decreased by 39% for the year ended December 31, 2015 compared to the same period in 2014. The average hedged price received for oil decreased by 24% for the year ended December 31, 2015 compared to the same period in 2014. Oil and Gas production volumes increased 29% for the year ended December 31, 2015 compared to the same period in 2014.

•	We review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly basis, known as a ceiling test. We recorded a non-cash ceiling impairment charge in each quarter of 2015, totaling $250 million for the year ended December 31, 2015.

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We finished drilling the last of 13 Mancos Shale wells for our 2014/2015 drilling program in the Piceance Basin. Nine wells were placed on production in 2015, all with favorable production results to date, exceeding our expectations. We deferred the completion of our four remaining wells due to insufficient gas processing capacity and our expectation of continued low commodity prices. During the second quarter of 2015, we also reduced our planned 2016 and 2017 capital expenditures due to our strategic decision to focus our oil and gas expertise on being a cost of service gas provider for our electric and natural gas utilities.

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On July 12, 2015 we entered into a definitive agreement to acquire SourceGas for approximately $1.89 billion, which included an estimated $200 million in capital expenditures through closing and the assumption of $760 million in long-term debt at closing. This acquisition closed on February 12, 2016. Financing activities related to this acquisition are detailed above in the 2016 Corporate activities.

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On June 26, 2015, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term one year, through June 26, 2020. This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate options.

•	On April 13, 2015, we entered into a new $300 million unsecured term loan. The loan has a two-year term with a maturity date of April 12, 2017. Proceeds of the term note were used to repay the existing $275 million term note due June 19, 2015.

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(a)	2016 reflects a planned outage at Wygen III and unplanned outages at Wyodak and Neil Simpson II.

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

(c)	2014 reflects planned overhauls for control system upgrades to meet NERC cyber security regulations on the Ben French CTs 1-4.

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(a)	Wygen I experienced an unplanned outage in 2016 and a planned outage in 2014.

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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)	Net of hedge settlement gains/losses

(b)	Impairment charges of $107 million and $250 million were recorded for the years ended December 31, 2016 and 2015, respectively.

(a)	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 21 of Notes to the Consolidated Financial Statements included in this Annual Report filed on Form 10-K.

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(a)

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. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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(a)	Projected benefit obligation (PBO) for pension plans 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)	Cash and cash equivalents include the proceeds from the November 23, 2015 issuance of common stock and equity units as discussed below.

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•	On January 13, 2016, we completed a public debt offering of $550 million in senior unsecured notes. The debt offering consists of $300 million of 3.95%, 10-year senior notes due 2026, and $250 million of 2.5%, 3-year senior notes due 2019. Net proceeds after discounts and fees were approximately $546 million; and

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On November 23, 2015, we completed the offerings of common stock and equity units. We issued 6.325 million shares of common stock for net proceeds of $246 million and 5.98 million equity units for net proceeds of $290 million. Each equity unit has a stated amount of $50 and consists of a contract to (i) purchase Company common stock and (ii) a 1/20, or 5%, undivided beneficial ownership interest in $1,000 principal amount of remarketable junior subordinated notes due 2028. Pursuant to the purchase contracts, holders are required to purchase Company common stock no later than November 1, 2018.

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•	$325 million, 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 16, 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 expense under this term loan was LIBOR plus a margin of 0.88%.

•	Extending our Revolving Credit Facility;

•	Renewing our shelf registration and ATM equity offering program;

•	Remarketing junior subordinated notes maturing in 2018;

•	Refinancing our term loan maturing in 2019; and

•	Paying off our $250 million, 3-year note maturing in 2019.

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(a)	2016 and 2015 reflect the impacts of non-cash impairments of our Oil and Gas properties totaling $107 million and $250 million, respectively.

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•	Cash earnings (income from continuing operations plus non-cash adjustments) were $63 million higher than prior year.

•	Net outflow from operating assets and liabilities was $144 million higher than prior year, primarily attributable to:

•	Cash inflows decreased by approximately $75 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 inflows decreased 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 increased by approximately $35 million as a result of changes in accounts payable and accrued liabilities driven primarily by acquisition and transition costs, and a reduction in uncertain tax positions liability, 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; and

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•	Cash inflows increased approximately $9.8 million for other operating activities compared to the prior year.

•	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);

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In 2016, we had higher capital expenditures of $19 million primarily at our Electric Utilities and Gas Utilities, driven by current year wind and natural gas generation additions at our Electric Utilities, and additional capital at our acquired SourceGas Utilities. This is partially offset by lower current year capital expenditures at our Oil and Gas segment. In 2015 our Oil and Gas segment completed their 2014/2015 Piceance drilling program, while 2016 had no further drilling capital deployed;

•	Our Oil and Gas segment divested of non-core assets, selling properties for $11 million; and

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

•	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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•	Net inflow from operating assets and liabilities of continuing operations was $128 million higher than prior year, primarily attributable to:

•	Cash inflows increased by approximately $11 million compared to the prior year as a result of decreased gas volumes in inventory due to milder weather and lower natural gas prices;

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Cash inflows from working capital increased, driven primarily by $52 million as a result of lower customer receivables and by $61 million as a result of lower working capital requirements for natural gas for the year ended December 31, 2015 compared to the prior year. Colder weather and higher natural gas prices during the first quarter 2014 peak winter heating season drove a significant increase in natural gas volumes sold, and in natural gas volumes purchased and fuel cost adjustments recorded in regulatory assets. These fuel cost adjustments deferred in the prior year are recovered through their respective cost mechanisms as allowed by state utility commissions;

•	Cash outflows increased approximately $11 million for other operating activities compared to the prior year, primarily by increased benefit plan expenses; and

•	Cash earnings (income from continuing operations plus non-cash adjustments) were $9 million lower than prior year.

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In 2015, we had higher capital expenditures of $57 million primarily due to our Oil and Gas segment completing the 2014/2015 Piceance drilling program, lower prior year capital affected by weather delays, and increased capital expenditures at our Coal Mine and Gas Utilities. Offsetting these 2015 capital expenditure increases is the construction of Cheyenne Prairie at our Electric Utilities segment occurring in the prior year; and

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

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Net Long-term borrowings were $315 million in 2015 reflecting a $25 million net increase in our Corporate term loan, and the $290 million issuance of our RSNs, net of issuance costs, compared to net long-term borrowings of $148 million in 2014 when South Dakota Electric and Wyoming Electric sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie and repaid $12 million of South Dakota Electric’s pollution control bonds;

•	In 2015, we issued 6.325 million shares of common stock for $246 million, net of issuance costs;

•	Net Short-term borrowings under the revolving credit facility were $9.3 million higher than the prior year;

•	Cash outflows for other financing activities increased by approximately $26 million driven primarily by $7 million of bridge facility fees paid in 2015, and proceeds of $22 million received in 2014 from the sale of an asset at our Power Generation segment, which under GAAP, this transaction did not qualify as the sale of an asset and the proceeds are presented as a financing activity; and

•	Cash dividends on common stock of $73 million were paid in 2015 compared to $70 million paid in 2014.

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

(b)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility property additions as of the years ended December 31, 2015 and 2014 have been reclassified from the Electric Utilities segment to the Gas Utilities segment. Property additions of $30 million and $22 million, respectively, previously reported in the Electric Utilities segment in 2015 and 2014 are now presented in the Gas Utilities segment.

(c)	In 2015, we drilled the last of 13 Mancos Shale wells for our 2014/2015 drilling program. We placed nine on production in 2015. Completion of the four remaining wells was deferred based on the positive results of our nine wells, insufficient gas processing capacity, and continued low commodity prices in 2016.

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(a)	On February 12, 2016, S&P reaffirmed BBB rating and maintained a Stable outlook following the closing of the SourceGas Acquisition, reflecting their expectation that management will continue to focus on the core utility operations while maintaining an excellent business risk profile following the acquisition.

(b)	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.

(c)	On February 12, 2016, Fitch affirmed BBB+ rating and maintained a Negative outlook following the closing of the SourceGas Acquisition, which reflects the initial increased leverage associated with the SourceGas acquisition.

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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: $126 million in 2017, $126 million in 2018, $121 million in 2019, $113 million in 2020 and $101 million in 2021. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2016.

(c)

Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas transportation and storage agreements, and gathering commitments for our Oil and Gas segment. The energy charges under the PPAs are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2016 and price assumptions using existing prices at December 31, 2016. Our transmission obligations are based on filed tariffs as of December 31, 2016. The gathering commitments for our Oil and Gas segment are described in Part I, Delivery Commitments, of this Annual Report filed on Form 10-K.

(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, Mining and Oil and Gas 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 2024.

(g)

In the first quarter of 2016, we reached a settlement in principle with IRS Appeals in regard to the like-kind exchange transaction associated with the gain deferred from the tax treatment related to the IPP Transaction and the Aquila Transaction. A settlement was also reached with respect to research and development credits and deductions. Both issues were the subject of an IRS Appeals process involving the 2007 to 2009 tax years. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

(h)

Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including interest rate swaps and commodity related contracts that have a negative fair value at December 31, 2016. 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 natural long position of crude oil and natural gas reserves and production, 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)

Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility accounts receivable has been reclassified from the Electric Utilities segment to the Gas Utilities segment. Accounts receivable of $6.8 million as of December 31, 2015, previously reported in the Electric Utilities segment is now presented in the Gas Utilities segment.

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(a)	Goodwill of $2.0 million and $6.3 million for December 31, 2014 and December 31, 2015, respectively, is now presented in the Gas Utilities segment as a result of the inclusion of Cheyenne Light’s Gas operations in the Gas Utilities segment, previously reported in the Electric Utilities segment. See above in this Note 1 for additional details.

(b)	Goodwill was recorded on the July 1, 2015 acquisition of Wyoming natural gas utility Energy West Wyoming, Inc., and natural gas pipeline assets from Energy West Development, Inc.

(c)	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 Oil and Gas segment are valued under the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third party sources and therefore support Level 2 disclosure.

•

The commodity contracts for the 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 data where market data for pricing is observable. 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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The 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. Our remaining interest rate swap as of December 31, 2016 expired in January 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, respectively.

(d)

Our deferred energy, fuel cost and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

(e)	Increase compared to 2015 was driven by the addition of the SourceGas employee benefit plans.

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

(c)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.

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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.

(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility net Property, Plant and Equipment of $117 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.

(a)	Net Property, Plant and Equipment includes full cost pool net assets of approximately $43 million.

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(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.

(a)	Accumulated depreciation, depletion and amortization at Corporate reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP.

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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.

•	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.

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

(b)	Includes the assets acquired in the SourceGas acquisition on February 12, 2016.

(c)	Corporate assets at December 31, 2015 include proceeds received from the November 23, 2015 equity offerings. These proceeds were subsequently used on February 12, 2016 to partially fund the SourceGas Acquisition.

(d)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Assets of $135 million, previously reported in the Electric Utilities segment in 2015 are now presented in the Gas Utilities segment.

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

(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility property additions of $30 million previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.

(c)	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. The 2015 acquisitions represent two acquisitions made by Wyoming Gas.

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

(b)	Effective January 1, 2016, Cheyenne Light’s natural gas utility results are reported in our Gas Utilities segment. Cheyenne Light’s gas utility Property, Plant and Equipment of $130 million, previously reported in the Electric Utilities segment in 2015 is now presented in the Gas Utilities segment.

(c)	Includes Property, Plant and Equipment acquired in the SourceGas acquisition on February 12, 2016.

(a)	Oil and Gas includes oil and gas property impairments (see Note 13).

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(a)	Oil and Gas includes ceiling test and equity investment impairments (see Note 13).

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

(b)	See Note 12 for RSN details.

(c)	Variable interest rate.

(d)	Includes deferred financing costs associated with our Revolving Credit Facility of $2.3 million and $1.7 million as of December 31, 2016 and December 31, 2015, 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 the remaining $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, 2016, 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. The 2015 Mining Revision to Prior Estimates reflects a change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions.

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•	Commodity price risk associated with our natural long position of crude oil and natural gas reserves and production, 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)	Crude in Bbls, gas in MMBtus.

(b)	These financial instruments were designated as cash flow hedges upon inception.

(c)	Refers to the maximum forward period hedged.

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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, 2016, 2,138,300 MMBtus were designated as cash flow hedges for the natural gas over-the-counter swaps purchased.

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

(a)	The $25 million in swaps expired in October 2016 and 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.

(b)	These swaps were settled on August 19, 2016.

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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 borrowings on our Revolving Credit Facility. 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.

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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 2016, 2015 and 2014 were determined by Monte Carlo simulation using a blended volatility of 24%, 21% and 23%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

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

(b)	To conform with the 2016 presentation of accelerated depreciation, amortization and other property-related differences, 2015 is net of deferred tax assets of $182 million, previously presented as an asset impairment and includes $184 million of a liability previously presented as mining development and oil exploration.

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(a)	The tax benefit includes additional percentage depletion deductions that were claimed with respect to the oil and gas properties involving prior tax years. Such deductions were primarily the result of a change in the application of the maximum daily limitation of 1,000 barrels of oil equivalent as allowed under the Internal Revenue Code.

(b)

The tax benefit relates to the release of after-tax interest expense that was previously accrued with respect to the liability for uncertain tax positions involving the like-kind exchange transaction effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. In addition, the tax benefit includes the release of reserves involving research and development credits and deductions. Both adjustments are the result of a re-measurement of the liability for uncertain tax positions predicated on an agreement reached with IRS Appeals in early 2016.

(c)

The flow-through adjustments related primarily to an accounting method change for tax purposes that allows us to take a current tax deduction for repair costs that continue to be capitalized for book purposes. In addition, flow-through adjustments were recorded related to an accounting method change for tax purposes that allows us to take a current tax deduction for certain indirect costs that continue to be capitalized for book purposes. 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.

(d)	Black Hills Colorado IPP went from a single member LLC, wholly-owned by Black Hills Electric Generation, to a partnership as a result of the sale of 49.9% of its membership interest in April 2016. The effective tax rate reflects the income attributable to the noncontrolling interest for which a tax provision was not recorded.

(e)	The effective tax rate for the year ended December 31, 2015 represents a tax benefit due to the pre-tax net loss.

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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)	Change from 2015 reflects a decrease in the discount rate offset by increased asset returns and a change in the mortality tables used in employee benefit plan estimates.

(a)	Assets of VEBAs and Grantor Trust.

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(a)

The Defined Benefit Pension Plans Accumulated Benefit Obligation for 2016 represents the obligation for the merged Black Hills Retirement Plan. The 2015 obligation represents the BHC Pension Plan and Black Hills Utility Holding, Inc. Pension Plan and has been combined for presentation purposes to conform to the 2016 merged plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2016 represents that obligation for the five postretirement plans maintained by BHC. The 2015 obligation represents the three 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 4.27% for the calculation of the 2017 net periodic pension costs.

(b)	The expected rate of return on plan assets is 6.75% for the calculation of the 2017 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 has a 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 inter-company 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 inter-company agreement, Wyoming Electric has agreed to sell 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.

•	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.

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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, 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.

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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 does not include volumes for natural gas liquids (NGLs) for historical periods.

(b)	A specific NYMEX price for NGL is 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. Presently, ethane is 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. For accounting purposes, consistent with prior years, the sales price for natural gas is adjusted for transportation costs and other related deductions when applicable, as further described in Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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•	We have no PUDs at December 31, 2016, and due to economic conditions in 2016, no new gross PUD locations were added for future drilling in the Piceance Mancos or Powder River Basin.

•	The number of locations and reconciliation of our proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of December 31, 2016 were:

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

ITEM 9A.	CONTROLS AND PROCEDURES

ITEM 9B.	OTHER INFORMATION

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ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

ITEM 11.	EXECUTIVE COMPENSATION

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

(1)

Includes 135,650 full value awards outstanding as of December 31, 2016, 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, 293,095 shares of unvested restricted stock were outstanding as of December 31, 2016, 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.

(a)	See (a) 3. Exhibits above.

(b)	See (a) 2. Schedules above.

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ITEM 16.	FORM 10-K SUMMARY

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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.