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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

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

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(1)

Cheyenne Prairie, a 132 MW natural gas-fired power generation facility was placed into commercial operations on October 1, 2014 to support the customers of Black Hills Power and Cheyenne Light. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Cheyenne Light and one combined-cycle, 95 MW unit that is jointly-owned by Cheyenne Light (40 MW) and Black Hills Power (55 MW).

(2)	Wygen III, a 110 MW mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power 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.

(3)	Wyodak, a 362 MW mine-mouth coal-fired power plant, is owned 80% by PacifiCorp and 20% by Black Hills Power. This baseload plant is operated by PacifiCorp and our WRDC coal mine supplies all of the fuel for the plant.

(4)	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.

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(1)	Wind represents approximately 5% of our purchased power for 2015, 2014 and 2013.

•	Black Hills Power’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 Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW of energy during heavy load timing intervals;

•	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 Project;

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Cheyenne Light’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 Cheyenne Light to purchase Black Hills Wyoming’s ownership interest in the Wygen I facility through 2019 and would be 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);

•	Cheyenne Light’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 Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50% of the facility’s output to Black Hills Power;

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•	Cheyenne Light’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 Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 MW of the facility’s output to Black Hills Power; and

•	Cheyenne Light and Black Hills Power’s Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light’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, Black Hills Power will provide MDU with 25 MW from its other generation facilities or from system purchases with reimbursement of costs by MDU;

•	Black Hills Power has an agreement through December 31, 2023 to serve 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, Black Hills Power 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, Black Hills Power will also provide the City of Gillette its operating component of spinning reserves; and

•	Black Hills Power’s 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:

(1)

Black Hills Power 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. Black Hills Power'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 -

◦	Black Hills Power, Cheyenne Light, 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.

◦	Black Hills Power and Cheyenne Light receive certain staffing and management services from BHSC for Cheyenne Prairie.

•	Jointly Owned Facilities -

◦	Black Hills Power, the City of Gillette and MDU are parties to a shared joint ownership agreement, whereby Black Hills Power 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)	Other revenue primarily consists of transmission revenue.

(b)	Results for 2014 include $1.8 million in technical service revenues for facility improvements at one of our large industrial customers.

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

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

(c)	Decreases in 2015 and 2014 generation primarily due to changes in commodity prices that impacted power marketing sales.

(d)	Includes wind power of 227,396 MWh, 224,229 MWh and 222,069 MWh in 2015, 2014 and 2013, respectively.

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(a)	Decrease in 2015 is primarily from the expiration in March 2015 of a 5 MW unit contingent capacity contract we had with MEAN.

(b)	Includes company uses, line losses, test energy and excess exchange production.

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(a)	Change in customers is due to classification change to Commercial billing in 2014 based on customer’s business type.

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(a)	Increase primarily represents the customer additions from Cheyenne Light’s 2015 system acquisitions of Energy West and MGTC.

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

(b)	The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism.

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

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(a)	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 allows methodology 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 Black Hills Power’s open access transmission tariff.

•	An annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. 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 Cheyenne Light’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. Additionally, 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.

•	Effective January 1, 2015, a rider to recover a return on the construction costs of a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

•	In Kansas, we have a tariff pass-through mechanism for weather normalization, as well as tariffs that provide timely recovery of certain capital expenditures and property tax fluctuations.

•	In Kansas and Nebraska, we are allowed to recover the portion of uncollectible accounts related to gas costs through GCAs.

•	In Iowa, we have a Capital Infrastructure Automatic Adjustment Mechanism that allows for recovery of certain capital infrastructure investments.

•	In Nebraska, we have an Infrastructure System Replacement Cost mechanism that allows for recovery of certain capital infrastructure investments.

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(a)	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.

(b)

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 also allows Colorado Electric to recover a return on the construction costs for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

(c)

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an increase for Black Hills Power of $6.9 million in annual electric revenue. The agreement was a Global Settlement and did not stipulate return on equity and capital structure. The SDPUC’s decision provides Black Hills Power 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. Black Hills Power 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.

(d)	On March 17, 2015, Iowa Gas filed with the IUB for a capital investment recovery surcharge increase of $0.9 million. Iowa Gas received approval from the IUB on May 28, 2015.

(e)	On April 6, 2015, Nebraska Gas filed with the NPSC for a capital investment recovery surcharge increase of $1.5 million. Nebraska Gas received approval from the NPSC on July 27, 2015.

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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, Black Hills Power 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 Black Hills Power 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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•	Power Generation

•	Coal Mining

•	Oil and Gas

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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.

(b)

On February 12, 2016, Black Hills Electric Generation entered into a definitive agreement to sell a 49.9%, non-controlling interest in Black Hills Colorado IPP for $215 million to AIA Energy North America LLC, an infrastructure investment platform managed by Argo Infrastructure Partners. The sale is expected to close in April of 2016, pending receipt of regulatory approval from FERC. Black Hills Colorado IPP will continue to own and operate the facility.

(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.

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•	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.

•	Shared Services Agreements

◦	Black Hills Power, Cheyenne Light 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, Cheyenne Light and Black Hills Power are parties to a Spare Turbine Use Agreement, whereby Black Hills Colorado IPP charges Black Hills Power and Cheyenne Light a monthly fee for the availability of a spare turbine to support the operation of Cheyenne Prairie Generating Station.

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

•	Jointly Owned Facilities

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

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•	Black Hills Power for use at its Neil Simpson II plant. This contract is for the life of the plant;

•	Cheyenne Light for use at its 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 Black Hills Power. 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. Black Hills Power 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 Black Hills Power, 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;

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•	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)	Proved reserves presented for 2013 do not include NGLs.

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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)	Production for reserve calculations does not include volumes for NGLs.

(b)	Revisions to previous estimates were primarily due to commodity price changes.

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(a)	The decrease to proved undeveloped reserves is primarily due to our completion efforts in 2015 on our existing wells and our decision to limit additional drilling and exploration, driven by current year economic conditions. See Note 21 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

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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 15% (44,469 gross and 28,933 net acres), 5% (20,668 gross and 8,970 net acres) and 2% (14,229 gross and 4,642 net acres) of our undeveloped acreage could expire in 2016, 2017 and 2018, 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 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 a business office with approximately 14,300 square feet and a service center and garage with an aggregate of approximately 29,000 square feet.

•	In Papillion, Nebraska, we own an office building consisting of approximately 36,600 square feet.

•	In Nebraska, Iowa, Colorado and Kansas we own various office, service center, storage, shop and warehouse space totaling over 283,100 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 156,300 square feet utilized by our Electric Utilities and our Coal 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 center in Lincoln, 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;

•	Approximately 107,100 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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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;

•	The trend of utilities building their own generation or looking for developers to develop and build projects for sale to utilities under turnkey arrangements;

•	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 and our generation capacity;

•	Fuel prices or fuel supply constraints;

•	Pipeline capacity and transmission constraints;

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

•	Changes in tax rates and policies.

•	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. The Utilities Group purchases 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 the Utilities Group’s 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, 2015, approximately 25% of our Utilities Group 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 29% of our employees are represented by a total of six 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;

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

•	Supply interruptions, work stoppages and labor disputes;

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

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

•	Weather interferences;

•	Availability and cost of fuel supplies;

•	Unexpected engineering, environmental and geological problems; and

•	Unanticipated cost overruns.

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Uncertainty about the effect of the Transaction on employees, customers, vendors and others may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the Transaction is completed, and for a period of time thereafter, and could cause vendors and others that deal with us to seek to change existing business relationships.

•	We cannot be assured that our credit ratings will not be lowered as a result of the Transaction or for any other reason. Any reduction in our credit ratings could adversely affect our access to capital, our cost of capital and our other operating costs, and our ability to refinance or repay our existing debt and complete new financings.

•	make it more difficult for us to repay or refinance our debts as they become due during adverse economic and industry conditions;

•	limit our flexibility to pursue other strategic opportunities or react to changes in our business and the industry in which we operate and, consequently, place us at a competitive disadvantage to competitors with less debt;

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•	require an increased portion of our cash flows from operations to be used for debt service payments, thereby reducing the availability of cash flows to fund working capital, capital expenditures, dividend payments and other general corporate purposes;

•	result in a downgrade in the credit rating of our indebtedness, which could limit our ability to borrow additional funds or increase the interest rates applicable to our indebtedness;

•	result in higher interest expense in the event of increases in market interest rates for both long‑term debt as well as short‑term commercial paper, bank loans or borrowings under our line of credit at variable rates;

•	reduce the amount of credit available to support hedging activities; and

•	require that additional terms, conditions or covenants be placed on us.

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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(1)	2015 includes the addition of a $300 million term loan which replaced the $275 million term loan, classified as short-term debt at December 31, 2014, and the issuance of $299 million of RSNs as part of our November 23, 2015 equity offerings.

(2)

2015 includes a non-cash after-tax ceiling test impairment charge 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 of this Annual Report on Form 10-K). 2013 includes $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs. 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. Reserves reflect the sale of the Williston Basin assets.

(3)

2015 includes incremental SourceGas Acquisition costs, after-tax of $6.7 million and after-tax internal labor costs attributable to the SourceGas Acquisition of $3.0 million that otherwise would have been charged to other segments. 2013 and 2012 include a $20 million and $1.2 million non-cash after-tax unrealized mark-to-market gain, respectively, related to certain interest rate swaps, while 2011 includes a $27 million non-cash after-tax unrealized mark-to-market loss, 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.

(4)	Discontinued operations in 2013, 2012 and 2011 include post-closing adjustments and operations relating to our Energy Marketing segment sold in 2012.

(5)	In November 2015, we issued 6.3 million shares of common stock, par value $1.00 per share at a price of $40.25. In November 2011, we issued 4.4 million shares of common stock, which diluted our earnings per share in subsequent periods.

(6)	Excludes Cheyenne Light.

(7)	Tons of coal decreased in 2012 due to the expiration of an unprofitable train load-out contract.

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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

•	add approximately $900 million in rate base assets;

•	add approximately 429,000 gas customers; and

•	increase our customer growth opportunities.

•	Our three electric utilities achieved 1st quartile reliability ranking with 66 customer minutes of outage time (SAIDI) in 2015 compared to industry averages (IEEE 2014 1st quartile is less than 115 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 3.56% for coal fired plants, 2.72% for natural gas plants, and 0.70% for diesel plants in 2015, compared to an industry average* of 4.45%, 3.92%, and 3.79%, respectively (*NERC GADS 2014 Data);

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•	Our power generation fleet availability was 93.09% for coal fired plants, 96.18% for natural gas fired plants, 99.07% for diesel fired plants, and 99.25% for wind generation in 2015 while the industry averages** were 84.92%, 88.85%, 93.79% and 96%, respectively (**NERC GADS 2014 data was used for coal, natural gas and diesel; eco-generation data was used for wind);

•	Our safety TCIR of 1.2 compares well to an industry average of 2.1* and our DART rate of 0.6 compares to an industry average of 1.1+ (+ Bureau of Labor Statistics (BLS)-all utilities of all sizes - most recent industry averages are 2013);

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Our OSHA TCIR rate during construction of our generating facilities is also significantly better than industry average with a TCIR rate of 2 during construction of the Wygen III coal-fired plant compared to an industry average of 5.1 for coal-fired plants, 1.3 during construction of the Pueblo Airport Generating Station natural-gas fired plant compared to an industry average of 4.4 for natural-gas fired plants, 0 during construction of the Busch Ranch wind farm compared to an industry average of 4.4 for wind construction and 0 during construction of the Cheyenne Prairie Generating Station natural-gas fired plant compared to an industry average (BLS) of 2.1 for fossil fuel electric power generation; and

•	Our coal mine completed four 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 six years without a lost time accident.

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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 utility 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 site, 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. This site has expansion potential. We 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 build and own the $109 million, 60 MW Peak View Wind Project. Pending final approvals and permits, construction is expected to commence in the second quarter of 2016. The wind project is expected to be placed into commercial operation by year‑end 2016; and

•

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 Black Hills Power and Cheyenne Light 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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•	completion on January 13, 2016 of 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; and

•	completion on November 23, 2015 of the offerings of common stock and equity units. We issued 6.325 million shares of common stock for gross proceeds of $255 million and 5.98 million equity units for gross proceeds of $299 million.

•

Fits regulated growth strategy. The SourceGas Acquisition is strategic and accretive, delivering on our commitment to earnings growth and long‑term shareholder value. SourceGas fits in terms of geography, size, scope and culture. By continuing to leverage our core competencies and regional expertise, by expanding our business in Colorado, Nebraska and Wyoming and expanding our footprint into Arkansas, we expect to realize operating efficiencies and add to the scale of our regulated utility business, benefiting both customers and shareholders.

•	Accretive to earnings. We expect the SourceGas Acquisition will be accretive to earnings per share beginning in 2017 and support long‑term earnings growth. Also, we expect the acquisition of SourceGas to generate cash flow to support investment in the business and shareholder returns.

•	Supports dividend growth. We recently increased our dividend for the 46th consecutive year and we have paid dividends continuously since 1942. The acquisition of SourceGas is expected to support additional dividend growth at a sustainable payout ratio.

•	Provides geographic and regulatory diversity. The addition of SourceGas increases our business diversity and adds a progressive and highly‑rated regulatory environment.

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•	On January 20, 2016 we executed a 10-year, $150 million notional, forward starting interest rate swap at an all-in interest rate of 2.09%, with a mandatory early termination date of April 12, 2017.

•	On October 2, 2015, we executed a 10-year, $250 million notional, forward starting interest rate swap at an all-in interest rate of 2.29%, with a mandatory early termination date of April 12, 2017.

(a)	Income (loss) from continuing operations in 2013 includes a $6.6 million after-tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of Black Hills Wyoming’s project financing and write-off of deferred financing costs.

(b)	Net income (loss) from in 2015 includes a non-cash after-tax ceiling test impairment charge 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.

(c)

2015 includes incremental SourceGas Acquisition costs, after-tax of $6.7 million and after-tax internal labor costs attributable to the SourceGas Acquisition of $3.0 million that otherwise would have been charged to other business segments. 2013 includes a $7.6 million after-tax make-whole premium and write-off of deferred financing costs relating to the early redemption of our $250 million notes and interest expense on new debt.

(d)	2013 includes a $20 million non-cash after-tax mark-to-market gain related to certain interest rate swaps.

(e)	Income (loss) from discontinued operations, net of tax includes the activities of Enserco, our Energy Marketing segment. See Note 22 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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On November 2, 2015, our utility subsidiaries submitted an application in Colorado, and on September 30, 2015, submitted applications in Iowa, Kansas, Nebraska, South Dakota and Wyoming, with respective state utility regulators, seeking approval for a Cost of Service Gas Program. The Cost of Service Gas Program is designed to provide long-term natural gas price stability for the Company’s utility customers, along with a reasonable expectation of customer savings over the life of the program. If approved, Black Hills will acquire natural gas reserves and/or drill wells to produce natural gas for the program. Based on historical performance, the cost of production is expected to be more stable and predictable than the spot market price of natural gas.

•	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 14% less than the same period in 2014.

•	In our Electric Utility 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.

•

Construction commenced in the second quarter of 2015 on Colorado Electric’s $65 million 40 MW natural gas-fired combustion turbine. As of December 31, 2015, approximately $35 million was expended, and the project is on schedule to be completed and placed into service in the fourth quarter of 2016. Construction riders related to the project increased gross margins by approximately $1.9 million for the year ended December 31, 2015.

•

On July 23, 2015, Black Hills Power received approval from the WPSC for a CPCN originally filed on July 22, 2014 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. Black Hills Power 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 third quarter of 2016.

•

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 Cheyenne Light. 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.

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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. The project is being built by Invenergy Wind Development Colorado LLC and is expected to be completed in the fourth quarter of 2016. 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 will purchase the project for approximately $109 million through progress payments throughout 2016, with ownership transfer occurring just before achieving commercial operation.

•

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 2017.

•

On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for Black Hills Power 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 Black Hills Power 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. Black Hills Power 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.

•

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 $65 million natural gas-fired combustion turbine that is currently being constructed to replace the retired W.N. Clark power plant.

•	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.

•

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. Using our current reserves information, further ceiling test impairments could occur in 2016 if commodity prices for crude oil and natural gas remain at current low levels.

•

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 expectation of continued low commodity prices and our intent to transition our oil and gas operation into a cost of service gas provider for our electric and natural gas utilities.

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On February 12, 2016, Black Hills Electric Generation entered into a definitive agreement to sell a 49.9%, non-controlling interest in Black Hills Colorado IPP for $215 million to AIA Energy North America LLC, an infrastructure investment platform managed by Argo Infrastructure Partners. The sale is expected to close in April of 2016, pending receipt of regulatory approval from FERC. Black Hills Colorado IPP will continue to own and operate the facility. The proceeds from the sale of our Black Hills Colorado IPP assets will be used to repay short-term debt.

•

Due to uncertainties related to the CPP issued by the EPA, the decision to exercise the option to purchase Wygen I by Cheyenne Light from Black Hills Wyoming has been delayed. Within the existing PPA between Black Hills Wyoming and Cheyenne Light expiring on December 31, 2022, Cheyenne Light has an option to purchase Black Hills Wyoming’s 76.5% ownership of Wygen I through 2019 at $2.55 million per MW adjusted for capital additions.

•

On February 12, 2016, Black Hills Utility Holdings acquired SourceGas Holdings, LLC from investment funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co., pursuant to the purchase and sale agreement executed on July 12, 2015 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. We funded the SourceGas Transaction with the following:

•	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

•	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.

•	We executed the following interest rate swaps to hedge the risks of interest rate movement between the hedge date and the expected pricing date for anticipated future long-term debt refinancings. These swaps are accounted for as cash flow hedges and any gain or loss is initially recorded in AOCI.

•	On January 20, 2016, we executed a 10-year, $150 million notional, forward starting interest rate swap at an all-in interest rate of 2.09%, with a mandatory early termination date of April 12, 2017.

•	On October 2, 2015, we executed a 10-year, $250 million notional, forward starting interest rate swap at an all in interest rate of 2.29%, with a mandatory early termination date of April 12, 2017.

•

On February 12, 2016, Moody's affirmed the BHC credit rating of Baa1 and maintained a negative outlook following our acquisition of SourceGas. Moody’s has maintained a negative outlook as BHC focuses on integrating the newly acquired SourceGas assets in the next 12 months, closing the sale of the Colorado IPP assets and implementing and utilizing an at-the-market (ATM) program.  In addition, the negative outlook reflects overall weaker consolidated metrics when compared to historical ranges.

•	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.

•

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.

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•	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.

•

Gas Utilities were favorably impacted by colder than normal weather during the first quarter of 2014, which was 14% colder than normal and 7% colder than the first quarter of 2013. This led to an increase in retail natural gas sold and offset unfavorable weather experienced through the remainder of 2014 when compared to 2013. Our service territories reported colder than normal winter weather as measured by heating degree days, compared to the 30-year average, but not as cold as 2013. Heating degree days for the full year in 2014 were 7% colder than normal but 2% less than the same period in 2013.

•	Mild weather was a contributing factor for our Electric Utilities during the year. Weather related demand during the peak summer months was tempered by significantly cooler temperatures within our service territories. Cooling degree days for the full year of 2014 were 29% lower than the same period in the prior year and 12% lower than normal.

•

On December 19, 2014, Colorado Electric received approval from the CPUC 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. The CPUC also authorized the implementation of a rider for a return on capital expenditures for a $65 million natural gas-fired combustion turbine that will replace the retired W.N. Clark power plant.

•	On December 16, Kansas Gas received approval from the Kansas Corporation Commission to increase annual base revenue by an estimated $5.2 million, effective January 1, 2015.

•

On October 1, 2014, Black Hills Power and Cheyenne Light placed into commercial service their jointly-owned Cheyenne Prairie generating station. Cheyenne Prairie is a 132 MW, $222 million natural gas-fired generating facility built to serve Black Hills Power and Cheyenne Light customers. Cheyenne Prairie was constructed on time and on budget. Construction financing costs were recovered through construction financing riders.

◦

On October 1, 2014, Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie. Black Hills Power issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 and Cheyenne Light issued $75 million of 4.53% coupon first mortgage bonds due October 20, 2044. Proceeds from Black Hills Power’s bond sale also funded the early redemption of its 5.35%, $12 million pollution control revenue bonds, originally due October 1, 2024.

◦

Black Hills Power and Cheyenne Light each received approval from the WPSC on rate cases associated with Cheyenne Prairie. On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt. On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase

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On March 31, 2014, Black Hills Power filed a rate request with the SDPUC to increase annual revenue by $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing was seeking a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Interim rates were implemented on October 1, 2014 when Cheyenne Prairie commenced commercial operations. On March 2, 2015, the SDPUC issued an order approving a rate stipulation and agreement authorizing an annual electric revenue increase for Black Hills Power of $6.9 million effective October 1, 2014 under a global settlement agreement.

•	On April 25, 2014, Cheyenne Light received FERC approval to establish rates for transmission services under their Open Access Transmission Tariff, effective May 3, 2014. The approval includes a return on equity of 10.6% and a capital structure of 54% equity and 46% debt.

•	On March 21, 2014, Black Hills Power retired the Ben French, Neil Simpson I and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. These plants were largely replaced by Black Hills Power’s share of Cheyenne Prairie.

•	On February 25, 2014, the CPUC issued a final order after rehearing, approving a CPCN for the retirement of Pueblo Unit #5 and #6, effective December 31, 2013.

•	BHC continued its efforts to acquire smaller public and municipal gas distribution systems adjacent to our existing service territories.

◦	On January 1, 2015, we closed a $6 million transaction to acquire the natural gas utility assets of MGTC, Inc., a northeast Wyoming system serving more than 400 customers. This system is operated by and consolidated into the results of Cheyenne Light.

◦

On October 14, 2014, we announced an agreement to acquire Energy West Wyoming, Inc., a Wyoming gas utility, and pipeline assets of Gas Natural, Inc. for $17 million. The gas utility serves approximately 6,700 customers, including service to Cody, Ralston and Meeteetse, Wyoming. The pipeline assets include a 30 mile gas transmission pipeline and a 42 mile gas gathering pipeline, both located near the utility service territory. This transaction closed July 1, 2015.

◦	During the first quarter of 2014, we acquired an additional gas system in Kansas, adding approximately 70 customers.

•	Coal Mining completed negotiations on the coal contract price increase with the third-party operator of the Wyodak plant. The new coal price of $18.25 per ton, an increase of approximately $4.75, was effective July 1, 2014.

•

On September 3, 2014, Black Hills Wyoming closed the sale of its 40 MW CTII natural-gas fired generating unit to the City of Gillette, Wyoming for approximately $22 million, upon expiration on August 31, 2014 of the PPA with Cheyenne Light. As part of the sale, Black Hills Wyoming will provide services to the City of Gillette through ancillary agreements, including an operating agreement and an economy energy PPA. The sale resulted in a deferred gain of $4.9 million which Black Hills Wyoming will recognize equally over the twenty-year term of the operating agreement.

•

Our southern Piceance Basin drilling program continued in 2014. During the third quarter, three Mancos Shale wells were drilled, cased and cemented. On March 6, 2014, the Summit Midstream cryogenic gas processing plant with a capacity of 20,000 Mcf per day started serving the company’s gas production in the southern Piceance Basin, including two Mancos Shale wells placed on production during the first quarter.

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•	Consolidated interest expense decreased by approximately $41 million in 2014, compared to 2013, due primarily to the refinancing activities occurring during the fourth quarter of 2013 and the extension of our Revolving Credit Facility under favorable terms on May 29, 2014.

•	On June 13, 2014, Fitch upgraded the BHC credit rating to BBB+ with a stable outlook.

•

On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially 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 for which the borrowing rates were reduced under the amended agreement.

•	On January 30, 2014, Moody’s upgraded the BHC credit rating to Baa1 from Baa2 with a stable outlook.

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

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

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(a)	Wygen I experienced planned outages in 2014 and 2013.

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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)	A ceiling test impairment charge of $250 million was recorded for the year ended December 31, 2015. If crude oil and natural gas prices remain at or near current levels, additional ceiling test impairment charges could occur in 2016.

(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)	NGL reserves for 2013 are not available and were included with MMcf of natural gas in 2013.

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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

•

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.

•	Evaluate refinancing options for our $300 million variable-rate Corporate term loan;

•	Evaluate the implementation of an “at-the-market” equity program;

•	Evaluate amendment and extension of our Revolving Credit Facility; and

•	Evaluate refinancing options for the assumption of SourceGas long-term debt.

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(a)	2015 reflects the impact of non-cash ceiling test impairments of our Oil and Gas properties totaling of $250 million.

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•	Net inflow from operating assets and liabilities of continuing operations was $123 million higher than prior year, primarily attributable to:

•	Cash inflows increasing 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;

•

Cash inflows increasing from working capital primarily driven 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 increasing 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.

•

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.

•

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 Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie and repaid $12 million of Black Hills Power’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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•	Cash earnings (income from continuing operations plus non-cash adjustments) were $44 million higher than prior year;

•	Net outflow from operating assets and liabilities of continuing operations were $49 million higher than prior year, primarily attributable to:

*	Increased working capital requirements of approximately $39 million resulting from higher commodity prices experienced in 2014 which created an increase in fuel cost adjustments recorded in regulatory assets at our Electric and Gas Utilities;

*	Increase in accounts receivable of approximately $17 million as a result of increased revenue and increased commodity costs in 2014;

*	Receipt in 2013 of approximately $8.4 million from a government grant relating to the Busch Ranch Wind Project.

•	A $10 million contribution in 2014 to our defined benefit plans compared to $13 million in 2013; and

•	2013 included cash outflows from operating activities of $1 million for post-closing adjustments resulting from the sale of our Energy Marketing segment in 2012.

•	In 2014, we had higher capital expenditures with an increase of $44 million primarily due to the increase at our Oil and Gas segment.

•	In 2014, Black Hills Power and Cheyenne Light sold $160 million of first mortgage bonds in a private placement to provide permanent financing for Cheyenne Prairie;

•	In 2014, we repaid $12 million of Black Hills Power’s pollution control bonds;

•	In 2014, we received $22 million from the sale of an asset at our Power Generation segment. Under GAAP, this transaction did not qualify as the sale of an asset and the proceeds are presented as a financing activity;

•	In 2014, net cash payments on our revolving credit facility increased $44 million over 2013, in addition to the 2013 revolving credit facility payments described below;

•

In 2013, we re-paid $250 million senior unsecured notes plus a make-whole premium of approximately $8.5 million, paid off the Black Hills Wyoming project debt for approximately $96 million with settlement of the associated interest rate swaps for approximately $8.5 million, repaid $55 million on Revolving Credit Facility and settled the de-designated interest rate swaps for approximately $64 million with proceeds from issuance of a senior unsecured notes for $525 million;

•	In 2013, we entered into a long-term Corporate term loan for $275 million which was primarily used to repay the $100 million long-term term loan, the $150 million short-term term loan and a portion of the Revolving Credit Facility; and

•	Cash dividends on common stock of $70 million were paid in 2014 compared to $68 million paid in 2013.

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

(b)	Includes 2015 Wyoming natural gas system acquisitions of $22 million.

(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 our expectation of continued low commodity prices.

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(a)	2016 forecasted capital expenditures for the electric utilities include approximately $97 million for the Peak View Wind Project and the remaining $29 million of Colorado Electric’s 40 MW natural gas fired generating unit.

(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 February 12, 2016, Moody’s affirmed Baa1 rating and maintained a Negative outlook following the closing of the SourceGas Acquisition. Moody’s has maintained a negative outlook as BHC focuses on integrating the newly acquired SourceGas assets in the next 12 months, closing the minority interest sale of Colorado IPP and implementing and utilizing an at-the-market (ATM) program.  In addition, the negative outlook reflects overall weaker consolidated metrics when compared to historical ranges.

(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: $80 million in 2016, $77 million in 2017, $74 million in 2018, $65 million in 2019 and $61 million in 2020. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2015.

(c)

Unconditional purchase obligations include the energy and capacity costs associated with our PPAs, capacity and certain transmission, gas purchases, gas transportation and storage agreements, and gathering commitments for our Oil and Gas segment. The energy charge under the PPAs and the commodity price under the gas purchase contracts are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2015 and price assumptions using existing prices at December 31, 2015. Our transmission obligations are based on filed tariffs as of December 31, 2015. A portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure, are carried out for 60 days. 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, Coal 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)	Years 1-3 include an estimated reversal of approximately $5.8 million associated with the gain deferred from the tax treatment related to the IPP Transaction and the Aquila Transaction.

(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, 2015. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments; and (2) a portion of our gas purchases are hedged. These hedges are in place to reduce our customers' underlying exposure to commodity price fluctuations. The impact of these hedges is not included in the above table.

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

(b)

BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric under the Build Transfer Agreement for construction of Peak View Wind Project. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the 2nd anniversary of the closing date. The guarantee decreases as progress payments are made. See additional details of this build transfer agreement in Note 19 of the Notes to Consolidated Financial Statements.

•	Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production and fuel procurement for certain of our gas-fired generation assets; and

•	Interest rate risk associated with our variable rate debt and our other short-term and long-term debt instruments as described in Notes 6 and 7 of our Notes to Consolidated Financial Statements.

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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)	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.

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(a)	Amortization expense for existing intangible assets is expected to be $0.2 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 and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant since these instruments are not traded on an exchange.

•

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.

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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.

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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 from the offering were $546 million;

•	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; and

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(a)	The plant acquisition adjustment is included in rate base and is being recovered with 15 years remaining.

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

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(a)	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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Black Hills Power 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. Black Hills Power 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 Black Hills Power with coal for its share of the Wyodak Plant, our Coal 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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Black Hills Power 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 - 200 MW West to East and 200 MW from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie.

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Black Hills Power 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 Coal Mining subsidiary supplies coal to Wygen III for the life of the plant.

•	Colorado Electric owns 50% of the Busch Ranch Wind Project 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 project 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 Coal 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)	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.

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

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

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

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(a)	Power Generation includes costs associated with interest rate swaps settled and write-off of deferred financing costs upon repayment of Black Hills Wyoming Project Financing and Corporate includes a write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt.

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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.

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(a)	Deferred financing costs on Cheyenne Prairie first mortgage bonds executed on October 1, 2014.

(b)	This project financing was repaid in 2013 and the deferred financing costs were written off.

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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, 2015, the restricted net assets at our Utilities Group were approximately $316 million.

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(a)	The Coal Mining Revision to Prior Estimates reflects the change in backfill yards and disturbed acreage used in calculating the estimated liability as well as changes in inflation rate assumptions.

(b)	The Oil and Gas Revision to Prior Estimates was due to a change in useful well lives used in calculating the estimated liability.

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•	Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production and fuel procurement for certain of our gas-fired generation assets; and

•	Interest rate risk associated with our variable rate debt and our other short-term and long-term debt instruments.

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(a)	Crude in Bbls, gas in MMBtu’s.

(b)	Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.

(a)	Term reflects the maximum forward period hedged.

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(a)	These swaps are designated to borrowings on our Revolving Credit Facility. These swaps are priced using three-month LIBOR, matching the floating portion of the related borrowings.

(b)	These swaps are designated as cash flow hedges of anticipated debt refinancings.

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(a)	These interest rate swaps were settled in the fourth quarter of 2013.

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(a)	Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b)	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 intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.

(b)	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

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(a)	The grant date fair values for the performance shares granted in 2015, 2014 and 2013 were determined by Monte Carlo simulation using a blended volatility of 21%, 23% and 20%, 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)	Majority of impairment deferred tax asset is related to oil and gas properties.

(b)	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.

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(a)	The tax benefit has remained relatively the same for each period presented, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015.

(b)

The tax expense recorded in 2015 included the re-measurement related to research and development credits and deductions, which increased tax expense. The combination of the re-measurement, continued accrual of after-tax interest expense associated with other uncertain tax positions primarily the like-kind exchange transaction, and pre-tax net loss resulted in a greater impact on the effective tax rate in 2015.

(c)

The flow-through adjustments relate 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. 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 our customers in the form of lower rates as a result of a rate case settlement that occurred in 2010. 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 a tax benefit consistent with the flow-through method. Such tax benefit has remained somewhat constant, but its impact on the effective tax rate is predicated on the level of pre-tax net income or loss as evidenced in 2015.

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(a)

The underlying net asset value in the Common Collective Trust - Real Estate fund is determined by appraisal of the properties held in the Trust. As part of the Trustee's valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with the professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the Trustee along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The fund does contain a participant withdrawal policy.

(b)

The fair value of the Hedge Funds is determined based on pricing provided or reviewed by the third-party administrator to our investment managers. While the input amounts used by the pricing vendor in determining fair value are not provided, and therefore, unavailable for our review, the asset results are reviewed and monitored to ensure the fair values are reasonable and in line with market experience in similar asset classes. Additionally, the audited financial statements of the funds are reviewed at the time they are issued.

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(a)	Change from 2014 reflects an increase in the discount rate and a change in the mortality tables used in employee benefit plan estimates.

(b)	Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.

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(a)	Assets of VEBA.

(b)	Benefits paid include payments of $6.1 million in 2014 made to terminated vested employees who elected lump-sum offerings.

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(a)	The expected rate of return on plan assets is 6.75% for the calculation of the 2016 net periodic pension cost.

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

•	Black Hills Power’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.

•	Black Hills Power 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.

•	Cheyenne Light’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 Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50% of the facility output to Black Hills Power.

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•	Cheyenne Light’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, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to Black Hills Power.

•	Colorado Electric’s PPA with Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW energy during heavy load timing intervals.

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

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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.

•	Black Hills Power 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, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves.

•	Black Hills Power 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.

(b)

BHC has guaranteed the full and complete payment and performance on behalf of Colorado Electric under the Build Transfer Agreement for construction of Peak View Wind Project. The guarantee terminates at the earlier of 1) when BHC or Colorado Electric has paid and performed all guaranteed obligations, or 2) the 2nd anniversary of the closing date. The guarantee decreases as progress payments are made. See additional details of this build transfer agreement in Note 19 of the Notes to Consolidated Financial Statements.

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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.

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•	The decrease in 2015 of 28 PUD locations is driven by low commodity prices and economics. The remaining six PUD locations are in the Williston Basin and require approximately $0.4 million of future investment.

•	Due to economic conditions in 2015, no new gross PUD locations were added for future drilling in the Williston Bakken, 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, 2015 were:

•	None of our PUD locations have been reflected in our reserves for five or more years. Consistent with SEC guidance, these PUD locations will be monitored and reported each year until either drilled or revised.

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

ITEM 9A.	CONTROLS AND PROCEDURES

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•	Employees involved with preparation and review of the ceiling test calculation have been trained to reinforce the understanding of the requirements associated with appropriately performing this calculation, particularly as it relates to deferred taxes.

•	The model used to calculate the ceiling test has been updated and refined to ensure the appropriate application of accounting for all components is embedded within the model.

•	We engaged an external consultant with experience in the Oil and Gas industry to assist in reviewing the ceiling test model in consideration of the risk associated with market or business changes.

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 129,178 full value awards outstanding as of December 31, 2015, 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, 200,615 shares of unvested restricted stock were outstanding as of December 31, 2015, 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

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

†	Indicates a board of director or management compensatory plan.