---

---

---

---

---

---

---

ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

---

---

(1)

The Osage, Ben French, and Neil Simpson I generating plants, having a combined capacity of 81.3 MW, were retired on March 21, 2014 due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. The remaining net book value of these plants is deferred as a Regulatory asset on the accompanying Consolidated Balance Sheets. We have requested recovery for the remaining net book values of these plants and prudent decommissioning costs of these units. The WPSC granted approval to our request in the Wyoming rate case approved in August 2014, and our request with the SDPUC is pending with a decision expected in March 2015.

(2)

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).

(3)	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.

(4)	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.

(5)	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. The wind farm became operational October 16, 2012.

---

•	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 accounted for as a capital lease on the accompanying Consolidated Financial Statements;

•	Colorado Electric’s PPA with Cargill expiring on December 31, 2015, which provides for the purchase of 50 MW of energy during heavy load timing intervals;

•	Colorado Electric’s PPA with Cargill expiring on December 31, 2016, which provides for the purchase of 50 MW of energy during light 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;

•

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. 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;

---

•	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 energy from Silver Sage 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.

•

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;

•	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:

•	Black Hills Power’s PPA with MEAN, whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III through May 2015.

(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.

---

•	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 also 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.

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

---

(a)	2013 includes $0.7 million and 2012 includes $2.1 million in construction savings incentives from the construction of the Pueblo Airport Generating Station.

(b)	Other revenue primarily consists of transmission revenue.

(c)	Increase in 2014 is primarily due to $1.8 million in technical service revenues for facility improvements at one of our large industrial customers.

---

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

(b)	W.N. Clark suspended operations in 2012.

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

(d)	Decrease in 2014 generation primarily due to increased commodity prices that impacted power marketing sales.

(e)	Includes wind power of 224,229 MWh, 222,069 MWh, and 199,079 MWh in 2014, 2013 and 2012, respectively.

---

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

---

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

---

---

(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.

---

---

---

---

---

---

---

•

In Wyoming, Cheyenne Light has an annual cost adjustment mechanism that allows us to pass the prudently-incurred costs of fuel and purchased power through to electric customers. Until October 1, 2014, at Cheyenne Light, our pass-through sharing mechanism relating to transmission and the PCA, returned 85% to the customer, and the Company retained 15%. Effective October 1, 2014, coal and coal related costs are passed through under an 85% / 15% distribution methodology, and purchased power costs, transmission, and natural gas costs are passed through under a 95% / 5% distribution methodology.

•

In South Dakota, Black Hills Power has 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 65% of off-system power marketing operating income. The modification also adjusts the 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.

•	In South Dakota, we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011, which recovers costs associated with generation plant environmental improvements.

•	We have an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of Black Hills Power’s open access transmission tariff.

•	We have an approved FERC Transmission Tariff that determines the revenue component of Cheyenne Light’s open access transmission tariff.

•

In Colorado, we have a quarterly ECA rider (the rider was semi-annual until August 1, 2013) 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%). Through 2013, this sharing percentage allowed 75% to the customers. 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.

•	On December 19, 2014, Colorado Electric received approval from the CPUC to implement a rider effective January 1, 2015 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.

---

(a)

On July 31, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 54% equity and 46% debt. The WPSC’s decision provides Cheyenne Light 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.

(b)

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. The WPSC’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.

(c)

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 seeks a return on equity of 10.25% and a capital structure of approximately 53.3% equity and 46.7% debt. Black Hills Power implemented interim rates on October 1, 2014, coinciding with Cheyenne Prairie’s commercial operation date. We expect a final decision from the SDPUC on our rate request by the end of the first quarter of 2015. Interim rates will be trued up as necessary based on the final approval.

(d)	On April 15, 2014, the IUB approved a capital investment recovery surcharge increase of $0.5 million.

(e)	On April 29, 2014, Kansas Gas filed a rate request with the KCC to increase annual revenue to recover infrastructure and increased operating costs. On October 24, 2014, a settlement agreement was reached between Kansas Gas, the KCC and intervenors to increase base rates by $5.2 million. On December 16, 2014, Kansas Gas received approval from the KCC to increase base rates by $5.2 million.

(f)

On April 30, 2014, Colorado Electric filed a rate request with the CPUC to recover increased operating expenses and infrastructure investments, including those for the Busch Ranch Wind Farm, placed in service late 2012. The filing also requested to implement a rider 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. 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, as well as approving implementation of the rider.

---

•

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. On May 5, 2014, Colorado Electric issued an all-source generation request for approximately 42 MW of summer seasonal firm capacity in 2017, 2018 and 2019 and up to 60 MW of eligible renewable energy resources to serve its customers in southern Colorado. Colorado IPP submitted solar and wind bids in response to this request. On December 23, 2014, the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that Colorado IPP’s bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration.

•

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.

---

---

---

---

---

---

•	Power Generation

•	Coal Mining

•	Oil and Gas

---

(1)	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.

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

(2)	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.

---

•	Economy Energy PPA and other ancillary agreements -

◦

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.

•	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.

◦	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.

---

•	Black Hills Power for use at its Neil Simpson II plant;

•	Cheyenne Light for use at its Wygen II plant;

•	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. 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;

•	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 are short-term and have terms of one to three years.

---

---

---

---

(a)	Proved reserves presented for 2013 and 2012 do not include NGL’s.

---

---

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

(b)	Revisions to previous estimates for 2013 were primarily due to commodity price changes.

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

(b)	Reflects sale of the majority of our Williston Basin assets in 2012.

(c)

Revisions to previous estimates for 2012 were primarily due to commodity price changes. Included in the total revisions is (27,051) MMcfe due to lower commodity prices, (2,422) MMcfe for dropped PUD locations due to the SEC requirement that PUD locations must be developed within five years or must be removed from PUD reserves, which was partially offset by positive performance revisions of (1,565) MMcfe in various basins.

---

(a)	We sold the majority of our Williston Basin assets in 2012.

---

(a)	The increase to proved undeveloped reserves is primarily due to new wells drilled. See Note 20 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

---

(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.

(a)

Approximately 18% (83,300 gross and 43,349 net acres), 15% (42,519 gross and 35,693 net acres) and 3% (12,502 gross and 6,375 net acres) of our undeveloped acreage could expire in 2015, 2016 and 2017, 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.

(b)	Reflects the sale of the majority of our Williston Basin assets in 2012.

---

---

---

•	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 24,400 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 256,500 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 164,500 square feet utilized by our Electric Utilities and our Coal Mining segments.

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

•	Approximately 37,600 square feet for a customer call center in Lincoln, Nebraska;

•	Approximately 48,400 square feet of office space in Denver, Colorado, of which we sublease approximately 10,100 square feet to a third party;

•	Approximately 116,000 square feet of various office, service center and warehouse space leased by the Gas Utilities;

•	Approximately 2,000 square feet of various office, service center and warehouse space leased by the Electric Utilities; and

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

---

---

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;

•	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;

•

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;

•	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 equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages. For example, as described in more detail under “Legal Proceedings,” a fire investigator concluded that a forest and grassland fire in the western Black Hills of Wyoming and South Dakota in 2012 was caused by the failure of a transmission structure owned, operated and maintained by Black Hills Power, and claims have been made against us related to the fire;

•	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 30% 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;

•	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.

---

---

---

---

---

---

---

---

---

---

---

---

ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 3.	LEGAL PROCEEDINGS

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

---

ITEM 6.	SELECTED FINANCIAL DATA

---

---

(1)

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 $17 million offset by an after-tax gain on sale of $19 million related to our Williston Basin assets. Reserves reflect the sale of the Williston Basin assets (see Notes 12 and 21 of the Notes to the Consolidated Financial Statements of this Annual Report on Form 10-K).

(2)

2011 and 2010 include a $27 million and $9.9 million non-cash after-tax unrealized mark-to-market loss, respectively, related to certain interest rate swaps; while 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. 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.

(3)	Discontinued operations include post-closing adjustments and operations relating to our Energy Marketing segment in 2013, 2012, 2011 and 2010.

(4)	During November 2011, we issued 4.4 million shares of common stock, which diluted our earnings per share in subsequent periods.

(5)	Excludes Cheyenne Light.

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

---

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

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

---

•	Our three electric utilities achieved 1st quartile reliability ranking with 74 customer minutes of outage time (SAIDI) in 2014 compared to industry averages (IEEE 2013 1st quartile is less than 85 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 2.7% for coal-fired plants, 2.8% for natural gas plants in 2014 and 0.1% for diesel plants, compared to an industry average* of 3.5%, 4.6% and 1.7%, respectively (*NERC GADS 2013 data);

•	Our power generation fleet availability was 94% for coal-fired plants, 95% for gas-fired plants, 96% for diesel-fired plants and 99% for wind generation in 2014 while the industry averages^ were 90%, 90%, 96% and 96%, respectively (^NERC GADS Data Base, 2013 most recent industry information);

•	Our safety TCIR of 2.0 compares well to an industry average of 2.8* and our DART rate of 1.1 compares to an industry average of 1.4+ (+ Most recent industry averages are 2012);

•

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

•	Our coal mine completed three 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 five years without a lost time accident.

---

•	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.

---

•

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 turbine project, was completed in the fourth quarter of 2012, as part of our plan to meet Colorado’s Renewable Energy Standard. This site also has expansion potential;

•

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. For example, under two 20-year PPAs we purchase a total of 60 MW of wind energy from wind farms located near Cheyenne, Wyoming for use at Black Hills Power and Cheyenne Light; 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.

---

•	Perform detailed reservoir analysis and apply proven technologies to our existing assets to maximize value;

•	Participate in a limited number of selective and meaningful exploration prospects;

•

Focus primarily on the Rocky Mountain region, where we can more easily integrate new opportunities with our existing crude oil and natural gas operations as well as our power generation activities. Specifically, we intend to focus our near term efforts on fully developing the substantial shale gas potential of our San Juan and Piceance Basin properties and participating in select oil exploration prospects with substantial upside opportunities;

•	Support the future capital requirements of our drilling program by stabilizing cash flows with a hedging program that mitigates commodity price risk for up to three years of future production; and

•	Enhance our crude oil and natural gas production activities with the construction or acquisition of mid-stream gathering, compression and treating facilities in a manner that maximizes the economic value of our operations.

---

•

On July 22, 2014, Black Hills Power filed a CPCN with the WPSC 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. Approval by the WPSC is anticipated in the second quarter of 2015. Black Hills Power has received approval from the SDPUC for a permit to construct the line.

---

•

On May 5, Colorado Electric issued an all-source generation request, including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request. On December 23, 2014 the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that our standalone bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration.

•

On December 19, 2014, Colorado Electric received approval from the CPUC for an annual electric revenue increase of $3.1 million with a return on equity of 9.83% 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.

---

---

(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)	Income (loss) from continuing operations in 2012 includes a $17 million non-cash after-tax ceiling test impairment loss and a $19 million after-tax gain on sale of our Williston Basin assets. See Notes 12 and 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(c)

Financial results of Enserco, our Energy Marketing segment, have been reclassified as discontinued operations in accordance with GAAP. When preparing this reclassification, certain indirect corporate costs and inter-segment interest expenses previously charged to our Energy Marketing segment could not be reclassified to discontinued operations of $0.6 million for 2012 and accordingly have been presented within Corporate. See Note 21 of the Consolidated Financial Statements in this Annual Report on Form 10-K.

(d)

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, while 2012 includes a $4.6 million after-tax make-whole premium for the early redemption of our $225 million notes and a $1.0 million write-off of deferred financing costs relating to early renewal of our Revolving Credit Facility.

(e)	2013 and 2012 include a $20 million and a $1.2 million non-cash after-tax mark-to-market gain, respectively, related to certain interest rate swaps.

(f)	Income (loss) from discontinued operations, net of tax includes the activities of Enserco, our Energy Marketing segment. See Note 21 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

---

•

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 Jan. 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 for Cheyenne Light of $8.4 million and $0.8 million for annual electric and natural gas revenue, respectively, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 54% equity and 46% debt.

---

◦

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 seeks 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. A final ruling from the SDPUC is expected in the first quarter of 2015.

•	On July 22, 2014, Black Hills Power filed a CPCN with the WPSC 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. Approval by the WPSC is anticipated in the second quarter of 2015.

•

On May 5, 2014, Colorado Electric issued an all-source generation request, including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request. On December 23, 2014 the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that our standalone bids were not among the highest ranked bids. However, two of the highest ranked bids provide an opportunity for Colorado Electric or our power generation segment to be partial or full owners of the facilities. At its deliberation in February 2015, the Commission determined none of the alternatives was acceptable, because of potential short-term rate impacts. The Commission discussed the possibility that Colorado Electric could more economically comply with the renewable energy standard by purchasing renewable energy credits. The purchase of renewable energy credits will be considered in a separate proceeding. After review of the Commission’s decision regarding the all source solicitation (which has not yet been issued), Colorado Electric will determine whether to seek reconsideration.

•	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 will be 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.

◦	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.

•

The company recently announced that Anthony Cleberg, executive vice president and chief financial officer, will retire at the end of March 2015. Richard Kinzley, previously vice president and controller and a 15-year veteran of the company, was appointed senior vice president and chief financial officer, effective January 1, 2015. In addition, the senior leadership team was expanded when Brian Iverson, previously vice president and treasurer and 11-year veteran of the company, was appointed senior vice president regulatory and government affairs and assistant general counsel.

•	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.

---

•	On September 17, 2013, the South Dakota Public Utilities Commission approved a general rate case settlement agreement authorizing an increase for Black Hills Power of $8.8 million, or 6.4%, in annual electric revenues effective June 16, 2013. The settlement agreement was confidential and certain terms were not disclosed.

•

On September 17, 2013, the SDPUC approved the construction financing rider in lieu of traditional AFUDC with an effective date of April 1, 2013. The rider allowed Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40% share of the total Cheyenne Prairie project cost that relates to South Dakota customers, while also saving customers money over the long-term. Cheyenne Light and Black Hills Power received approval from the WPSC for a similar construction financing rider in 2012 which allowed Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately a 60% share of the project costs related to serving Wyoming customers, while also lowering the overall cost of the project to customers.

•

Utility results for 2013 were favorably impacted by cold weather while 2012 utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. Our service territories reported colder winter weather, as measured by heating degree days, compared to the 30-year average and the prior year. Heating degree days for the full year in 2013 were 9% higher than weighted average norms for our Gas Utilities and 25% higher than the same period in 2012.

•	During 2013, Cheyenne Light and Black Hills Power commenced construction on Cheyenne Prairie. Project costs for plant construction and associated transmission were estimated at $222 million, of which approximately $156 million was spent as of December 31, 2013.

•	In April 2013, Colorado Electric filed an Energy Resource Plan with the CPUC addressing its projected resource requirements through 2019. The resource plan identified a 40 MW, simple-cycle, natural gas-fired turbine as the replacement of W.N. Clark. On January 6, 2014, the CPUC issued its initial written decision approving construction of the turbine.

•	On April 15, 2013, the IUB approved a Capital Infrastructure Automatic Adjustment Mechanism effective April 25, 2013, for $0.2 million. This adjustment mechanism requires an annual filing, therefore, subsequent filings will vary in size based on eligible infrastructure replacements and the timing of future general rate case filings.

•	On November 25, 2013, the NPSC approved an Infrastructure System Replacement Cost Recovery Charge that provided for an annual revenue increase of $1.4 million.

•	On December 31, 2013, Colorado Electric retired W.N. Clark and Pueblo Units #5 and #6. These facilities, and certain Black Hills Power generating facilities, are being permanently retired primarily due to state and federal environmental regulations. The affected plants are listed in the table below with their operations suspension date and their ultimate retirement date:

•	Gas Utilities continued efforts to acquire small gas distribution systems adjacent to their existing gas utility service territories. During 2013, five small gas systems with a total of approximately 900 customers were acquired.

---

•	In 2013, our Oil and Gas segment drilled and completed two horizontal wells in the Mancos Shale formation in the Piceance Basin. These wells are part of a transaction in which we earned approximately 20,000 net acres of Mancos Shale leasehold in the Piceance Basin in exchange for drilling and completing the two wells.

•

Black Hills Wyoming entered into an agreement to sell its 40 MW CTII natural-gas fired generating unit to the City of Gillette 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 a 20-year operating agreement and a 20 year economy energy PPA. The sale closed in September 2014.

•

On September 27, 2012, our Oil and Gas segment sold approximately 85% of its Williston Basin assets, including approximately 73 gross wells and 28,000 net leasehold acres, for net cash proceeds of approximately $228 million. We recognized a gain of $29 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and had the effect of reducing the depreciation, depletion and amortization rate after the sale.

•	Coal Mining continued operations under its revised mine plan. Mining operations moved in August 2012, to an area with lower overburden ratios, which reduced mining costs in 2013.

•	In the second quarter of 2012, our Oil and Gas segment recorded a $27 million non-cash ceiling test impairment loss as a result of continued low natural gas prices.

•

On November 19, 2013, we completed a public debt offering of $525 million in senior unsecured debt at 4.25% due November 30, 2023. Proceeds were used to redeem our $250 million, 9% senior unsecured notes, pay off the Black Hills Wyoming project financing and related interest rate swaps, settle the de-designated interest rate swaps, partially pay down our Revolving Credit Facility and the remainder was used for other corporate purposes.

•

On September 25, 2013, Moody’s raised our corporate credit rating to Baa2 from Baa3 with continued positive outlook. On July 24, 2013, S&P raised our corporate credit rating to BBB from BBB- with a stable outlook. They also raised our senior unsecured rating to BBB from BBB-. On May 10, 2013, Fitch Ratings raised our Issuer Default Rating to BBB from BBB- with a positive outlook. Subsequently on January 30, 2014, Moody’s upgraded our corporate credit rating to Baa1 and changed their outlook to stable.

•	On June 21, 2013, we replaced our $150 million and $100 million term loans with a two-year term loan for $275 million at an interest rate of 1.125% over LIBOR.

•	We recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of $30 million in 2013 compared to a $1.9 million unrealized mark-to-market loss on these swaps in 2012. These swaps were settled in November 2013.

---

---

(a)	2014 reflects a planned overhaul on Neil Simpson II for emissions controls upgrades.

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

---

---

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

---

---

(a)	Reduction in overburden was due to relocating mining operations in the second half of 2012 to an area of the mine with lower overburden.

(b)	Reduction in coal reserves was due to revisions in coal modeling based upon engineering data, changes in coal limit boundaries and current coal production.

---

---

(a)	Net of hedge settlement gains/losses

*	The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The decreased depletion rate in 2013 is primarily driven by the Williston Basin sale in 2012. See Note 21 of Notes to the Consolidated Financial Statements included in this Annual Report filed on Form 10-K.

---

---

---

---

---

---

---

---

---

---

---

•	Redeem our $250 million senior unsecured 9.0% notes originally due on May 15, 2014. This repayment occurred on December 19, 2013, for approximately $261 million which included a make-whole provision of approximately $8.5 million and accrued interest.

•	Repay our variable interest rate Black Hills Wyoming project financing with a remaining balance of $87 million originally due on December 9, 2016 and settle the interest rate swaps designated to this project financing of $8.5 million.

•	Settle the $250 million notional de-designated interest rate swaps for approximately $64 million.

•	Pay down $55 million of the Revolving Credit Facility.

•	Remainder was used for general corporate purposes.

•	Evaluate alternatives for the $275 million term loan due June 19, 2015.

---

---

•	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 $1.0 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 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.

•	Cash earnings (income from continuing operations plus non-cash adjustments) were $24 million higher than prior year;

•

Net outflow from operating assets and liabilities of continuing operations were $14 million higher than prior year. The variance primarily related to increased natural gas inventory, a decrease in accounts payable of approximately $9.0 million due to the expiration of Colorado Electric’s contract with PSCo at December 31, 2011, the return of cash collateral from our de-designated interest rate swaps of $6.0 million and other normal working capital changes;

•	A $13 million contribution in 2013 to our defined benefit plans compared to $25 million in 2012; and

•	2013 included cash outflows from operating activities of $0.9 million for post-closing adjustments resulting from the sale of our Energy Marketing segment in 2012 compared to 2012, which included a $21 million cash inflow from operating activities in our Energy Marketing segment.

---

•	In 2012, proceeds from sale of assets was $254 million which included $228 million from the sale of a majority of our Williston Basin assets by our Oil and Gas segment and $25 million from the partial sale of the Busch Ranch Wind project;

•	In 2012, we received proceeds of $108 million from the sale of Enserco; and

•	In 2013, we had comparable capital expenditures to 2012, with an increase of $5.6 million primarily due to the construction of Cheyenne Prairie.

•

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;

•	In 2012, we repaid our $225 million senior unsecured 6.5% notes with proceeds from the sale of Williston Basin assets and Black Hills Power repaid its $6.5 million Pollution Control Revenue Bonds. The redemption of the notes required a make-whole provision payment of $7.1 million;

•	In 2012, we repaid short-term borrowings from proceeds from the sale of Enserco partially offset by the use of short-term borrowings to fund the construction of Cheyenne Prairie; and

•	Cash dividends on common stock of $68 million were paid in 2013 compared to $65 million paid in 2012.

---

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

(b)	2014 and 2013 include costs relating to Cheyenne Prairie which began construction in the spring of 2013; and 2012 included construction of our 50% ownership in the Busch Ranch Wind Project.

(c)	Increase in 2014 expenditures was due to drilling and completion delays experienced in 2013.

---

(a)	On January 30, 2014, Moody’s upgraded the BHC credit rating to Baa1 with a Stable outlook.

---

(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: $68 million in 2015, $65 million in 2016, $65 million in 2017, $65 million in 2018 and $60 million in 2019. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2014.

(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 2014 and price assumptions using existing prices at December 31, 2014. Our transmission obligations are based on filed tariffs as of December 31, 2014. 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 7 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 $6.2 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, 2014. 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.

---

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

•	Commodity price risk associated with our natural long position 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 5 and 6 of our Notes to Consolidated Financial Statements.

---

---

---

(a)	Excludes unamortized premium or discount.

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

---

---

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

---

---

---

---

---

---

---

---

---

---

(1)	BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

---

---

---

---

*	Amortization expense for existing intangible assets is expected to be $0.2 million for each year of the next five years.

---

•	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.

---

---

(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. Increases in the current year balances as of December 31, 2014 are primarily due to higher natural gas prices driven by demand and market conditions during our peak winter heating season. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

(e)	Increases are due to a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.

---

---

---

---

(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.

---

---

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

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

•

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.

•

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.

•

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.

(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)	Includes accruals for property, plant and equipment.

(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)	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 (see Note 5).

---

(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 21).

(b)	Oil and Gas includes a ceiling test impairment (see Note 12).

(c)	Corporate includes a make-whole provision from early repayment of long-term debt.

---

(a)	Discount on note initially reflected in deferred financing costs at December 31, 2013.

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

(c)	Variable interest rate.

---

•	Redeem our $250 million senior unsecured 9.0% notes originally due on May 15, 2014. This repayment occurred on December 19, 2013, for approximately $261 million which included a make-whole provision of approximately $8.5 million and accrued interest which are included in Interest expense on the accompanying Consolidated Statements of Income;

•	Repay our variable interest rate Black Hills Wyoming project financing with a remaining balance of approximately $87 million originally due on December 9, 2016, as well as the interest rate swaps designated to this project financing of $8.5 million which is included in Interest expense on the accompanying Consolidated Statements of Income;

•	Settle the $250 million notional de-designated interest rate swaps for approximately $64 million;

•	Pay down approximately $55 million of the Revolving Credit Facility; and

•	Remainder was used for general corporate purposes.

(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.

---

•	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, 2014, the restricted net assets at our Utilities Group were approximately $315 million.

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

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

---

•	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.

---

(a)	Crude in Bbls, gas in MMBtu.

(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)	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.

---

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

---

---

---

---

---

---

---

(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.

---

(a)	The grant date fair value of the 2014 awards was $12.58 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.1% risk free interest rate, 29.4% expected price volatility, 2.9% expected dividend yield and a 7 year expected life.

---

(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.

---

(a)	The grant date fair values for the performance shares granted in 2014, 2013 and 2012 were determined by Monte Carlo simulation using a blended volatility of 23%, 20% and 21%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date.

(b)

The weighted-average fair value for the liability portion at December 31, 2014 was determined by the actual performance for the 2012 to 2014 performance period at the top of the peer group resulting in a 200% of target payout, and determined by Monte Carlo simulations for the 2013 to 2015 performance period and 2014 to 2016 performance period projecting a 157% and 51% of target payouts, respectively.

---

---

---

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

---

(a)

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.

---

---

---

---

---

---

---

(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.

---

(a)	Change from 2013 reflects a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.

(b)	Reflects Board of Directors approval of an increase to Company’s contribution to RMSA accounts.

---

(a)	Assets of VEBA.

(b)	Benefits paid include payments made to terminated vested employees who elected a lump-sum offering of $6.1 million in 2014 and $13 million in 2013.

---

---

(a)	The expected rate of return on plan assets is 6.75% for the calculation of the 2015 net periodic pension cost.

---

•

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.

•	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, 2015, which provides for the purchase of 50 MW energy during heavy load timing intervals.

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

---

•	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.

•

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 April 1, 2015. Under this contract, MEAN purchases 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.

•	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.

---

---

---

(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.

---

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

(b)	Reflects the sale of the majority of the Williston Basin assets during 2012.

(c)	A specific NYMEX price for NGL is not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, iso butane, 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.

---

•	In 2013, we had 23 gross PUD locations for 4.7 Bcfe; all of the locations were in the Williston, Piceance and San Juan Basins. In 2014, seven locations in the Williston Bakken Shale were drilled and we invested $3.9 million and developed 0.6 Bcfe. One PUD in the San Juan Basin was dropped for economic reasons. Two PUD locations in the Williston Bakken were sold in 2014.

•	Thirteen gross PUD locations remain undrilled as of December 31, 2014. The remaining 2013 PUD locations require approximately $10.5 million of future investment, and when drilled will develop approximately 3.2 Bcfe. Twelve locations are in the Williston Bakken and one location is in the Piceance Basin.

•	In 2014, we added 21 gross PUD locations for future Williston Bakken, Piceance Mancos and Powder River Basin drilling.

•	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, 2014 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.

---

(a)	Reflects the sale of the majority of the Williston Basin assets during 2012 recorded under the full-cost method of accounting.

---

(a)	Reflects sale of Williston Basin assets in 2012.

---

*	Required payment, triggered by the sale of the property, arising from a contractual obligation contained in the original participation agreement with the property operator.

---

(a)	2012 includes transaction related costs, net of tax, of $2.5 million for the year ended December 31, 2012.

---

(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $4.8 million, $12 million, $2.0 million and $0.5 million after-tax in the first, second, third and fourth quarters, respectively.

(b)

Fourth quarter 2013 includes $7.6 million after-tax for a 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 and 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.

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

ITEM 9A.	CONTROLS AND PROCEDURES

ITEM 9B.	OTHER INFORMATION

---

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

---

ITEM 11.	EXECUTIVE COMPENSATION

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

(1)

Includes 218,192 full value awards outstanding as of December 31, 2014, comprised of restricted stock units, performance shares and Director common stock units. The weighted average exercise price does not include the restricted stock units, performance shares or common stock units. In addition, 233,692 shares of unvested restricted stock were outstanding as of December 31, 2014, which are not included in the above table because they have already been issued.

(2)	Shares available for issuance are from the 2005 Omnibus Incentive Plan. The 2005 Omnibus Incentive Plan permits the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock based awards.

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

---

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

---

3.	Exhibits

---

---

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

†	Indicates a board of director or management compensatory plan.

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

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

---

---

---

---

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

†	Indicates a board of director or management compensatory plan.