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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

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(1)

Construction of a 132 megawatt gas-fired power generation facility is underway to support the customers of Black Hills Power and Cheyenne Light. The facility will include one simple-cycle, 37 megawatt combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 megawatt unit that will be jointly owned by Cheyenne Light (40 megawatts) and Black Hills Power (55 megawatts). This facility is expected to be completed in the fourth quarter of 2014.

(2)	Wygen III, a 110 megawatt mine-mouth coal-fired power plant, is operated by Black Hills Power. Black Hills Power has a 52 percent ownership interest, MDU owns 25 percent and the City of Gillette owns the remaining 23 percent interest. Our WRDC coal mine supplies all of the fuel for the plant.

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

(4)

Operations at Osage were suspended Oct. 1, 2010, and Ben French was suspended on Aug. 31, 2012, due to the availability of more economical generation alternatives when evaluating costs to retrofit these plants to comply with environmental standards, including EPA regulations. Osage, Ben French and Neil Simpson I will be retired on or before March 21, 2014. While the net book value of these plants is estimated to be immaterial at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates and costs will be deferred as Regulatory assets on the accompanying Consolidated Balance Sheets.

(5)	Colorado Electric’s W.N. Clark (42 megawatts) and Pueblo Units #5 and #6 (29 megawatts) were retired as of Dec. 31, 2013.

(6)	Busch Ranch Wind Farm, a 29 megawatt wind farm, is operated by Colorado Electric. Colorado Electric has a 50 percent ownership interest in the wind farm and AltaGas owns the remaining 50 percent. Colorado Electric has a 25-year REPA with AltaGas for their 14.5 megawatts of power from the wind farm. The wind farm became operational Oct. 16, 2012.

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•	Black Hills Power’s PPA with PacifiCorp expiring on Dec. 31, 2023, which provides for the purchase of 50 megawatts of coal-fired baseload power;

•	Colorado Electric’s PPA with Black Hills Colorado IPP expiring on Dec. 31, 2031, which provides 200 megawatts 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 Dec. 31, 2014, whereby Colorado Electric purchases between 25 megawatts and 50 megawatts of economy energy based on various timing intervals throughout 2014;

•	Colorado Electric’s PPA with AltaGas expiring on Oct. 16, 2037, which provides up to 14.5 megawatts of wind energy from AltaGas’ owned interest in the Busch Ranch Wind Project;

•	Cheyenne Light’s PPA with Black Hills Wyoming expiring on Aug. 31, 2014, whereby Black Hills Wyoming provides 40 megawatts of energy and capacity from its Gillette CT;

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Cheyenne Light’s PPA with Black Hills Wyoming expiring on Dec. 31, 2022, whereby Black Hills Wyoming provides 60 megawatts 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 megawatt adjusted for capital additions and reduced by depreciation over a 35 year life beginning Jan. 1, 2009 (approximately $5 million per year);

•	Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 3, 2028, which provides up to 29.4 megawatts of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility’s output to Black Hills Power;

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•	Cheyenne Light’s 20-year PPA with Duke Energy expiring on Sept. 30, 2029, which provides up to 30 megawatts of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 20 megawatts 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 percent ownership 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 megawatts from its other generation facilities or from system purchases with reimbursement of costs by MDU;

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The City of Gillette owns a 23 percent ownership 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 megawatts 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 megawatts 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 megawatts of unit-contingent capacity from Neil Simpson II and 5 megawatts of unit-contingent capacity from Wygen III through May 2015; and

•	Cheyenne Light’s agreement with Basin Electric, whereby Cheyenne Light will supply 40 megawatts of capacity and energy through Sept. 30, 2014, and a separate agreement whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014.

(1)

Black Hills Power owns 35 percent 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 percent 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 megawatts from West to East, and 200 megawatts from East to West. Black Hills Power's electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids.

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•	Shared Services Agreements -

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

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

•	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.

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(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)	Off-system sales revenue during part of 2010 was deferred until a sharing mechanism was approved by the CPUC in December 2011. As a result, Colorado Electric had deferred $8.4 million in off-system revenue which was all recognized in December 2011.

(c)	Other revenue primarily consists of transmission revenue.

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

(b)	Includes wind power of 222,069 megawatt-hours, 199,079 megawatt-hours and 189,255 megawatt-hours in 2013, 2012 and 2011, respectively.

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

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

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

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

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In September 2013, the SDPUC approved a construction financing rider for Black Hills Power effective April 1, 2013, which allows for recovery of construction financing costs from customers during the construction period of Cheyenne Prairie in lieu of traditional AFUDC. The rider allows Black Hills Power to earn and collect a rate of return during the construction period on the total project cost that relates to South Dakota customers. This rider is similar to the rider approved by WPSC effective Nov. 1, 2012, which allows Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period of Cheyenne Prairie on approximately 60 percent of the total project cost that relates to Wyoming customers. These riders increased gross margin by approximately $6.9 million in 2013.

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In Wyoming, Cheyenne Light has annual cost adjustment mechanisms that allow us to pass the prudently-incurred cost of fuel and purchased power through to electric customers. Until July 1, 2012, at Cheyenne Light, our pass-through mechanism relating to transmission and the ECA was subject to a $1.0 million threshold: we collected or refunded 95 percent of the increase or decrease that exceeded the $1.0 million threshold, and we absorbed the increase or retained the savings for costs below the threshold as well as the 5 percent not collected or refunded above the threshold. Effective July 1, 2012, the $1.0 million threshold and its accompanying 95/5 percent distribution methodology was eliminated and replaced by a sharing mechanism that returned 85 percent to the customer and allowed the company to retain 15 percent.

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In South Dakota, Black Hills Power has an annual adjustment clause which provides for the direct recovery of increased fuel and purchased power 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 percent 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.

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In Colorado, we have a quarterly ECA rider (the rider was semi-annual until Aug. 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, where the customer received 75 percent through 2013. This sharing percentage increases to 90 percent to the customers in 2014 and thereafter. 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 us an annual Transmission Cost Adjustment (TCA) rider, from which we recover nine months of actual transmission investment and three months of forecasted investment, with an annual true-up mechanism.

•	In Kansas, we have a weather normalization tariff that provides a pass-through mechanism for weather margin variability that occurs from the level used to establish base rates to be paid by the customer, as well as tariffs that provide for more timely recovery for certain capital expenditures and fluctuations in property taxes.

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

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

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

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(1)

Iowa Gas filed a request for a Capital Infrastructure Automatic Adjustment Mechanism with the IUB in December 2012, which reflected a request for recovery of costs since our prior rate case in 2010. On March 15, 2013, the IUB determined that certain capital infrastructure investments were not eligible for recovery through this mechanism and on March 26, 2013, Iowa Gas filed a revised proposed tariff. 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.

(2)

In December 2012, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase of $13.7 million, or 9.94 percent, to recover investment in distribution and transmission lines, generation plant upgrades, environmental compliance and increased operating costs. On Sept. 17, 2013, the SDPUC approved a rate increase of $8.8 million, or 6.4 percent, effective June 16, 2013.

(3)

In December 2012, Black Hills Power filed a request with the SDPUC to use a construction financing rider during the construction of Cheyenne Prairie in lieu of traditional AFUDC. This rider is similar to the one approved by the WPSC in 2012 for Cheyenne Light and Black Hills Power for Wyoming customers. On Jan. 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, and on Sept. 17, 2013, the SDPUC approved the construction financing rider effective April 1, 2013. The rider allows Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40 percent share of the total project cost that relates to South Dakota customers.

(4)	In August 2013, Nebraska Gas filed with the NPSC an application requesting authority to establish an Infrastructure System Replacement Cost Recovery Charge mechanism. In an order dated Nov. 25, 2013, the NPSC approved a settlement with the Public Advocate that provided for a revenue increase of $1.4 million.

(5)	In December 2013, Cheyenne Light filed a rate case with the WPSC requesting electric and natural gas revenue increases of $12.8 million and $1.3 million, respectively, to recover investment in Cheyenne Prairie, existing infrastructure and increased operating costs. The filing seeks a return on equity of 10.25 percent and a capital structure of 54 percent equity and 46 percent debt.

(6)	In January 2014, Black Hills Power filed a rate case with the WPSC requesting an electric revenue increase of $2.8 million to recover investment in Cheyenne Prairie, existing infrastructure and increasing operating costs. The filing seeks a return on equity of 10.25 percent and a capital structure of 53 percent equity and 47 percent debt.

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Colorado. Colorado adopted a renewable energy standard that has two components: (i) electric resource standards and (ii) a two percent 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) 12 percent of retail sales through 2014; (ii) 20 percent of retail sales from 2015 to 2019; and (iii) 30 percent of retail sales by 2020. Of these amounts, 3 percent 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 percent. 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. In 2014, our Colorado Electric subsidiary will conduct an all-source solicitation to acquire additional electricity which may include electricity from renewable energy resources. In 2014, our Colorado Electric subsidiary will also file its renewable energy standard plan with the CPUC for the years 2015 through 2017.

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Montana. In 2005, Montana established a renewable portfolio standard that requires public utilities to obtain a percentage of their retail electricity sales from eligible renewable resources. In March 2013, Black Hills Power filed a petition with the MTPSC requesting a waiver of the renewable portfolio standards primarily due to exceeding the applicable "cost cap" included in the standards. However, 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 percent of their retail electricity supply from renewable energy sources by 2015.

•	Wyoming. Wyoming currently has no renewable energy portfolio standard.

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•	Power Generation

•	Coal Mining

•	Oil and Gas

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(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.

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•	Shared Services Agreements -

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

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

◦	Colorado IPP and Black Hills Wyoming also 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 for their share of the Wygen I generating facility for the life of the plant.

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Black Hills Power for use at its Ben French, Neil Simpson I and Neil Simpson II plants. Effective Aug. 31, 2012, Black Hills Power suspended operations at the 25 megawatt Ben French plant and announced the retirement of the Ben French plant and the 21.8 megawatt Neil Simpson I plant effective March 21, 2014. We sold approximately 120,000 tons per year to Ben French when it was operable and sell approximately 130,000 tons of coal per year to Neil Simpson I;

•	the 362 megawatt Wyodak power plant owned 80 percent by PacifiCorp and 20 percent 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 megawatt Wygen III power plant owned 52 percent by Black Hills Power, 25 percent by MDU and 23 percent 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 megawatt Wygen I power plant owned 76.5 percent by Black Hills Wyoming and 23.5 percent 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.

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

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(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.

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

(b)

Revisions to previous estimates for 2011 were primarily due to the SEC requirement that PUD locations must be developed within five years or must be removed from proved undeveloped reserves. Included in the total revisions are (23,647) MMcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2,315 MMcfe in various basins. Revisions due to cost and commodity pricing were less than one percent of total reserve quantities.

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(a)	Reflects sale of 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.

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(a)

Approximately 10 percent (87,689 gross and 23,648 net acres), 19 percent (87,748 gross and 44,136 net acres) and 15 percent (46,458 gross and 34,374 net acres) of our undeveloped acreage could expire in 2014, 2015 and 2016, 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.

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•	In Rapid City, S.D., 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, Colo., 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, Wyo., 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, Nebr., 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 236,500 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 97,000 square feet utilized by our Electric Utilities and our Coal Mining segments.

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•	Approximately 8,800 square feet for an operations and customer call center in Rapid City, S.D.;

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

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

•	Approximately 108,600 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.

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ITEM 1A.	RISK FACTORS

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

•	Our inability to secure adequate 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 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.

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•	Operational limitations imposed by environmental and other regulatory requirements;

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Interruptions to supply of fuel and other commodities used in generation and distribution. 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;

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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 31 percent 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;

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

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

•	Weather interferences;

•	Availability and cost of fuel supplies;

•	Unexpected engineering, environmental and geological problems; and

•	Unanticipated cost overruns.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 3.	LEGAL PROCEEDINGS

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

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ITEM 6.	SELECTED FINANCIAL DATA

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(1)

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, 2012 and 2009 include a $20 million, $1.2 million and a $36 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.

(2)

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.)

(3)	2009 Net income includes a $28 million non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties and a $17 million after-tax gain on sale of a 23.5 percent ownership interest in Wygen I.

(4)	Discontinued operations include post-closing adjustments and operations relating to our Energy Marketing segment in 2013, 2012, 2011, 2010 and 2009, and the assets sold in the IPP Transaction for 2009.

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

(6)	Excludes Cheyenne Light.

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

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

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

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•	Our power generation fleet achieved 1st Quartile Reliability ranking with less than 65 minutes (SAIDI) in 2013 compared to industry averages^^ (^^2012 Edison Electric Institute, less than 83.96 minutes and IEEE, less than 93 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 2.5 percent for coal-fired plants and 1.3 percent for natural gas plants in 2013, compared to an industry average* of 7 percent and 5 percent, respectively (*NERC GADS 2012 data);

•	Our natural gas generation fleet achieved a starting reliability of 99 percent in 2013 while the industry averaged** approximately 97 percent (**IEEE Data Base 2012);

•	Our power generation fleet availability was 97 percent for coal-fired plants, 97 percent for gas-fired plants, 97 percent for diesel-fired plants and 99 percent for wind generation in 2013 while the industry averages^ were 86 percent, 92 percent, 94 percent and 96 percent, respectively (^NERC Data Base, 2012 most recent industry information);

•	Our safety record is exemplary with a TCIR rate of 1.7 compared to an industry average of 2.8* for TCIR and a DART rate of 0.9 compared to an industry average of 1.4+ for DART (+ Most recent industry averages are 2012);

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Our OSHA TCIR rate during construction of our generating facilities is also significantly better than industry average with a TCIR rate of 2 during 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, and 0 during construction of the Busch Ranch wind farm compared to an industry average of 4.4 for wind construction. Our Cheyenne Prairie construction TCIR rate is currently on track to be below industry average;

•	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 three years without a lost time accident.

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•	Customers - since the generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable than if the power was purchased from the open market through wholesale contracts that are renegotiated over time;

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

•	Investors - investors are poised that a long-term, reasonable, stable rate of return may be earned on their investment;

•	All - a lower risk profile may improve credit ratings which, in turn, can benefit both consumers and investors by lowering our cost of capital.

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Colorado legislative mandates apply to our electric utility segment regarding the use of renewable energy. Therefore, we pursue cost-effective initiatives with the regulators that will allow us to meet our renewable energy requirements. Where permitted, we will seek to construct renewable generation resources as rate base assets, which will help mitigate the long-term customer rate impact of adding renewable energy supplies. For example, the Busch Ranch Wind site, a 29 megawatt 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 significant 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 megawatts of wind energy from wind farms located near Cheyenne, Wyo. for use at Black Hills Power and Cheyenne Light; and

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

•	Through detailed reservoir analysis, apply proven technologies to our existing assets to maximize value;

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

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Primarily focus 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;

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

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•

Similar to the construction financing rider approved by the WPSC effective Nov. 1, 2012, for Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on the portion of the financing costs related to serving Wyoming customers, the SDPUC approved a construction financing rider for Black Hills Power’s South Dakota customers effective April 1, 2013. On Dec. 2, 2013, Cheyenne Light filed a rate case with the WPSC requesting electric and natural gas revenue increases of $13 million and $1.3 million, respectively, to recover the construction of Cheyenne Prairie and an increase in operating costs. Black Hills Power filed a rate case on Jan. 17, 2014, with the WPSC requesting an electric revenue increase of $2.8 million to recover investment in Cheyenne Prairie, existing infrastructure and increasing operating costs. During the first quarter of 2014, Black Hills Power also intends to file a rate case in South Dakota to recover its investment in Cheyenne Prairie.

•

On April 30, 2013, Colorado Electric filed a revised Electric Resource Plan with the CPUC addressing its projected resource requirements through 2019 and seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant to comply with Colorado Clean Air – Clean Jobs Act. On Jan. 6, 2014, the CPUC issued its initial written decision approving a settlement with Colorado Electric on this resource plan, which included the approval to construct a 40 megawatt gas-fired combustion turbine to replace the retirement of the W.N. Clark power plant and to retire the aging natural gas-fired steam turbines, Pueblo Units #5 and #6. A final written order from the CPUC is expected in the first quarter of 2014.

•

On Oct. 16, 2013, the CPUC denied Colorado Electric's application for approval of a wind solicitation for the acquisition of up to 30 megawatts of wind energy for its electric system. This solicitation and related requests for proposal were reviewed by an independent evaluator who verified that our Power Generation segment's bid was the lowest cost to customers. The CPUC found that the calculated customer benefits over the 20 year evaluation period were insufficient for all of the bids and stated its preference to consider renewable energy needs in Colorado Electric's Electric Resource Plan hearings held in November 2013. The settlement approved by the CPUC on Jan. 6, 2014, denied any additional wind generation at this time, but indicated that the acquisition of eligible energy resources would be considered in the 2015 to 2017 renewable energy plan to be filed in May 2014.

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(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 and $2.2 million for 2012 and 2011, respectively, 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 $7.6 million after-tax expense 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, 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)	Includes a $20 million non-cash after-tax mark-to-market gain on certain interest rate swaps in 2013, a $1.2 million non-cash after-tax mark-to-market gain on those same interest rate swaps in 2012 and a $27 million non-cash after-tax mark-to-market loss in 2011 on those same 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.

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•	On Jan. 17, 2014, Black Hills Power filed a request with the WPSC to increase annual electric revenues by $2.8 million, to recover investments made in electric infrastructure, including Cheyenne Prairie currently under construction. The filing seeks a return on equity of 10.25 percent and a capital structure of approximately 53 percent equity and 47 percent debt.

•	On Dec. 2, 2013, Cheyenne Light filed a rate case with the WPSC requesting annual electric and natural gas revenue increases of $12.8 million, and $1.3 million, respectively, to recover investment in Cheyenne Prairie, and existing infrastructure and increasing operating costs. The filing seeks a return on equity of 10.25 percent and a capital structure of 54 percent equity and 46 percent debt.

•	On Sept. 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 percent, in annual electric revenues effective June 16, 2013. The settlement agreement was confidential and certain terms were not disclosed.

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On Sept. 17, 2013, the SDPUC approved the construction financing rider in lieu of traditional AFUDC with an effective date of April 1, 2013. The rider allows Black Hills Power to earn and collect a rate of return during the construction period on its approximately 40 percent share of the total 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 November 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 percent share of the project costs related to serving Wyoming customers, while also lowering the overall cost of the project to customers. These riders resulted in an increase to gross margin of $6.9 million in 2013.

•

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 degree days, compared to the 30-year average and the prior year. Heating degree days for the full year in 2013 were 9 percent higher than weighted average norms for our Gas Utilities and 25 percent higher than the same period in 2012.

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During 2013, Cheyenne Light and Black Hills Power commenced construction on Cheyenne Prairie, a facility which will include one simple-cycle, 37 megawatt combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 megawatt unit that will be jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Light will own 40 megawatts and Black Hills Power will own 55 megawatts of the combined-cycle unit. Commercial operation is expected in the fourth quarter of 2014. Project costs for plant construction and associated transmission are estimated at $222 million of which approximately $156 million has been spent to date.

•

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 megawatt, simple-cycle, natural gas-fired turbine as the replacement of W.N. Clark. Additionally, a CPCN was submitted recommending the retirement of Pueblo Unit #5 and #6. On Jan. 6, 2014, the CPUC issued its initial written decision approving the construction of a 40 megawatt gas-fired combustion turbine to replace W.N. Clark and approving the CPCN to the closure of Pueblo Unit #5 and #6. In conjunction with this same energy resource plan, the CPUC denied Colorado Electric’s application for approval to acquire up to 30 megawatts of wind energy.

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

•	On Dec. 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.

•	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.

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Black Hills Wyoming entered into an agreement to sell its 40 megawatt CTII natural-gas fired generating unit to the City of Gillette for approximately $22 million and a 20-year economy energy power purchase agreement, subject to closing adjustments. The sale is expected to close in August 2014 upon the expiration of an existing power sale agreement. The sale is subject to FERC approval and certain other requirements included in the contract.

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On Sept. 27, 2012, our Oil and Gas segment sold approximately 85 percent 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 commenced 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.

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On Nov. 19, 2013, we completed a public debt offering of $525 million in senior unsecured debt at 4.25 percent due Nov. 30, 2023. Proceeds were used to redeem our $250 million, 9 percent 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 for other corporate purposes.

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On Sept. 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 Jan. 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 percent 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.

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•	Our return on investments made in the Utilities Group was positively impacted by new and interim rates and tariffs implemented in three utility jurisdictions during 2012. Consequently, year-to-date revenues were positively impacted for rate increases in 2012 that were not in effect in the prior periods (dollars in millions):

•	Colorado Electric’s $230 million, 180 megawatt power plant near Pueblo, Colo. began commercial operations and started serving utility customers on Jan. 1, 2012. New rates and cost adjustments were effective Jan. 1, 2012, providing an additional $36 million in gross margins at Colorado Electric for the year ended Dec. 31, 2012.

•	On June 18, 2012, the WPSC approved a $2.7 million increase in annual electric revenue and a $1.6 million increase in annual natural gas revenue with a rate of return of 9.6 percent and a capital structure of 54 percent equity and 46 percent debt for Cheyenne Light. New rates were effective July 1, 2012.

•

On June 4, 2012, Colorado Gas filed a request with the CPUC for an increase in annual gas revenues to recover capital investments and increased operation and maintenance expenses. The filing was required by the CPUC as part of a 2008 rate case settlement. The CPUC approved a $0.2 million revenue increase with new rates effective Dec. 10, 2012. The settlement includes a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.

•

2012 utility results were unfavorably impacted by warm weather, particularly at the Gas Utilities. Our service territories reported warmer winter weather, as measured by degree days, compared to the 30-year average and the prior year. Heating degree days year-to-date were 13 percent lower than weighted average norms for our Gas Utilities. When compared to colder than normal weather during the same period in 2011, heating degree days were 14 percent lower than the same period in 2011 for our Gas Utilities. For our Electric Utilities, although summer temperatures were above normal, weather-related demand was tempered by lower humidity in 2012 than 2011 in our service territories.

•	Cheyenne Light and Black Hills Power received final approvals and permits for Cheyenne Prairie. The WPSC approved the CPCN authorizing the construction, operation and maintenance for the new 132 megawatt natural gas-fired electric generation facility and related gas and electric transmission in Cheyenne, Wyo.

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Cheyenne Light and Black Hills Power received approval from the WPSC to use a construction financing rider for Cheyenne Prairie in lieu of traditional AFUDC. This allows Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately a 60 percent share of the project costs related to serving Wyoming customers, while also lowering the overall cost of the project to customers. This rider was effective Nov. 1, 2012, resulting in an increase to gross margin of $0.2 million in 2012. Black Hills Power filed for a similar construction financing rider in South Dakota. On Jan. 17, 2013, the SDPUC approved a stipulation with interim rates effective April 1, 2013, subject to refund.

•

Colorado Electric completed construction of the 29 megawatt Busch Ranch wind project as part of its plan to meet Colorado’s Renewable Energy Standard. Colorado Electric’s 50 percent share of this project cost approximately $25 million and began serving Colorado Electric customers on Oct. 16, 2012. Colorado Electric entered into a 25-year REPA to purchase the remaining 50 percent wind energy produced by the project. On Jan. 30, 2013, Colorado Electric received approval notification from the United States Treasury for an award letter grant of $8.4 million for our share of the wind project.

•	Black Hills Power and Colorado Electric announced plans to suspend plant operations at six older coal-fired and natural gas-fired facilities totaling 152 megawatts primarily due to state and federal environmental regulations and cost to retrofit.

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On Sept. 27, 2012, our Oil and Gas segment sold approximately 85 percent of its Williston Basin assets, including approximately 73 gross wells and 28,000 net leasehold acres, for net cash proceeds of $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.

•	Coal Mining commenced operations under its revised mine plan in 2012. 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.

•	Construction of gas-fired generation at Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric was completed and the plant was placed into commercial operations on Jan. 1, 2012. The 200 megawatt project cost approximately $261 million.

•	On Feb. 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring Feb. 1, 2017. The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million.

•	On June 24, 2012, we extended for one year our $150 million term loan at an interest rate of 1.1 percent over LIBOR.

•	On Oct. 31, 2012, we redeemed our $225 million senior unsecured, 6.5 percent notes scheduled to mature on May 15, 2013.

•	We recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of $1.9 million in 2012 compared to a $42 million unrealized mark-to-market loss on these swaps in 2011.

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(a)	2012 reflects a planned overhaul at Wygen II. 2011 reflects a major overhaul and an unplanned outage at the Neil Simpson II plant and the PacifiCorp-operated Wyodak plant.

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(a)	Wygen I experienced a planned outage in 2013.

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(a)	Decrease in tons of coal sold is due to the Dec. 31, 2011 expiration of a coal sales agreement with PacifiCorp’s Dave Johnston Plant in Wyoming.

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

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

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(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.

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•	Redeem our $250 million senior unsecured 9.0 percent notes originally due on May 15, 2014. This repayment occurred on Dec. 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 Dec. 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.

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•	Review long-term debt financing options, including the potential issuance of utility first mortgage bonds, for a portion of the estimated $222 million Cheyenne Prairie capital project.

•	Extension of our Revolving Credit Facility which expires in 2017.

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

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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 Dec. 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.

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•	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.

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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 and settled 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 percent 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.

•	Cash earnings (income from continuing operations plus non-cash adjustments) were $47 million higher than prior year;

•	Net inflows from operating assets and liabilities of continuing operations of $40 million higher than prior year. The increase primarily related to decreased gas volumes in inventory, the decrease in accounts payable of approximately $9.0 million due to the expiration of Colorado Electric’s contract with PSCo at Dec. 31, 2011, and other normal working capital changes;

•	A $25 million contribution in 2012 to our defined benefit plans compared to $11 million in 2011; and

•	A $14 million increase in net cash inflows from discontinued operations in 2012 compared to 2011.

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•	Cash proceeds from assets sold during 2012, including $228 million from the sale of approximately 85 percent of our Williston Basin assets by our Oil and Gas segment, $25 million from the sale of a 50 percent ownership interest in the Busch Ranch Wind project, and $108 million from the sale of Enserco; and

•	In 2012, we had lower capital expenditures of $92 million primarily due to the completion of construction of our Pueblo generation facility.

•

During 2012, approximately $110 million of the proceeds from the sale of Enserco were used to pay down short-term borrowings on the Revolving Credit Facility. Additional borrowings on the Revolving Credit Facility were primarily used for our working capital needs, while in 2011 we increased short-term borrowings by approximately $196 million primarily due to our continued construction in Colorado;

•	In 2012, we repaid our $225 million senior unsecured 6.5 percent bonds 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 bonds required a make-whole provision payment of $7.1 million;

•	Cash dividends on common stock of $65 million were paid in 2012 compared to $59 million paid in 2011; and

•	In 2011, we issued common stock for proceeds of $123 million primarily from an equity forward transaction.

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

(b)	2013 includes costs relating to Cheyenne Prairie which began construction in the spring of 2013; 2012 included construction of our 50 percent ownership in the Busch Ranch Wind Project; and 2011 included costs relating to construction of the 180 megawatt natural gas-fired generation facility at Colorado Electric.

(c)	2011 includes costs relating to the construction of the 200 megawatt natural gas-fired power generation facility at Black Hills Colorado IPP.

(d)	Decrease in expenditures due to drilling and completion delays.

(1)	Capital expenditures for our Electric Utilities are forecasted to include approximately $68 million associated with the construction of Cheyenne Prairie during 2014.

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(a)	On July 24, 2013, S&P upgraded our credit rating to BBB with a Stable outlook.

(b)	On Sept. 25, 2013, Moody’s upgraded the BHC credit rating to Baa2 with a Positive outlook.

(c)	On May 10, 2013, Fitch upgraded our credit rating to BBB with a Positive outlook.

*	On July 24, 2013, S&P upgraded the BHP credit rating to A- with a Stable outlook.

**	On Sept. 25, 2013, Moody’s upgraded the BHP credit rating to A2. Subsequently, on Jan. 30, 2014, Moody’s upgraded the BHP credit rating to A1.

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

(b)

The following amounts are estimated for interest payments over the next five years based on a mid-year retirement date for long-term debt expiring during the identified period: $62 million in 2014, $60 million in 2015, $59 million in 2016, $59 million in 2017, and $59 million in 2018. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of Dec. 31, 2013.

(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 2013 and price assumptions using existing prices at Dec. 31, 2013. Our transmission obligations are based on filed tariffs as of Dec. 31, 2013. 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 2023.

(g)	Years 1-3 include an estimated reversal of approximately $6.3 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 Dec. 31, 2013. These amounts have been excluded as it is impractical to reasonably estimate the final amount and/or timing of any associated payments. (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. (3) The obligations presented above do not include inter-company transactions and obligations negotiated for the construction of Cheyenne Prairie. This 132 megawatt generating facilities is expected to cost $222 million for which we have secured 100 percent of the procurement contracts as of Dec. 31, 2013.

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

•	Interest rate risk associated with our variable rate debt and our other short-term and long-term debt instruments as described in Notes 5 and 6 of our Notes to Consolidated Financial Statements.

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(a)	Certain interest rate swaps designated as cash flow hedges were settled during 2013. See Note 8 of the Notes to the Consolidated Financial Statements in this Annual Report on Form10-K.

(b)	These de-designated swaps were settled in November 2013 for approximately $64 million. Pre-tax non-cash unrealized gain recognized on these swaps prior to settlement was $30 million.

(a)	Excludes unamortized premium or discount.

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

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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*	Cash and cash equivalents include cash of discontinued operations of $37 million and $16 million at Dec. 31, 2011 and 2010 respectively.

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(1)	BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES

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

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•	The commodity option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted 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 basis swaps for the Oil and Gas segment are valued under the market approach using the instrument’s current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which 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.

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•

The interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

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(a)	Recovery of costs, but 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 of costs, we are allowed a return on approximately $25 million.

(d)	In addition to recovery of costs, we are allowed a return on approximately $5.4 million.

(e)	Approximately $13 million is included in our rate base calculations as a reduction to rate base.

(f)	Approximately $2.6 million is included in our rate base calculations as a reduction to rate base.

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(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 Dec. 31, 2031.

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

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Black Hills Power owns a 20 percent interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. Black Hills Power receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying Black Hills Power with coal for its share of the Wyodak Plant, our Coal Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

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Black Hills Power also owns a 35 percent 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 megawatts - 200 megawatts West to East and 200 megawatts from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie.

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Black Hills Power owns 52 percent 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 percent 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 percent of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Coal Mining subsidiary during the life of the facility. We retain responsibility for plant operations.

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

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

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(a)	The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded for 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 the write-off of deferred financing costs and a make-whole provision from early repayment of long-term debt (see Note 5).

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(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 (see Note 5).

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(a)	Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation.

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(a)	This debt repaid. See Debt Transactions discussed below.

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

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•	Redeem our $250 million senior unsecured 9.0 percent notes originally due on May 15, 2014. This repayment occurred on Dec. 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 Dec. 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;

•	Remainder was used for general corporate purposes.

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•	Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of Dec. 31, 2013, the restricted net assets at our Utilities Group were approximately $88 million.

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(a)	The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate and market risk premium.

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

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

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(a)	Crude in Bbls, gas in MMBtu.

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

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

(b)

At Dec. 31, 2012, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps. The portion of the swaps that were designated to Black Hills Wyoming were settled upon repayment of the Black Hills Wyoming project financing. See Note 5.

(c)	Maximum terms in years reflect the amended early termination dates. If the early termination dates were not extended, the swaps would have required cash settlement based on the swap value at the termination date. These swaps were settled during the fourth quarter of 2013.

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(a)

The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.

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(a)	Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

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

(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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(a)	The grant date fair value of the 2013 awards was $7.65 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 1.4 percent risk free interest rate, 29.3 percent expected price volatility, 3.8 percent 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.

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(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 during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit consistent with the flow-through method. Such tax benefit has remained somewhat constant, but its impact on the effective tax rate is predicated on the level of pre-tax net income as evidenced in 2011.

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(a)

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

(b)

The fair value of Level 3 is determined based on pricing provided or reviewed by 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 will be reviewed at the time they are issued.

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

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(a)	Assets of VEBA

(b)	2013 Benefits paid includes a one-time $13 million payment made to terminated vested employees who elected a lump-sum offering.

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(a)	The expected rate of return on plan assets is 6.75 percent for the calculation of the 2014 net periodic pension cost.

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•	Black Hills Power’s PPA with PacifiCorp, expiring Dec. 31, 2023, for the purchase of 50 megawatts 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 Dec. 31, 2023. The agreement provides 50 megawatts of capacity and energy to be transmitted annually by PacifiCorp.

•	Cheyenne Light’s PPA with Duke Energy’s Happy Jack wind site, expiring Sept. 3, 2028, provides up to 30 megawatts of wind energy from Happy Jack to Cheyenne Light. Under a separate inter-company agreement, Cheyenne Light sells 50 percent of the facility output to Black Hills Power.

•	Cheyenne Light’s PPA with Duke Energy’s Silver Sage wind site, expiring Sept. 30, 2029, provides up to 30 megawatts of wind energy. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 megawatts of energy from Silver Sage to Black Hills Power.

•	Colorado Electric’s PPA with Cargill expiring Dec. 31, 2014, whereby Colorado Electric purchases 50 megawatts of economy energy.

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

•	Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014.

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(a)	This PPA with PSCo expired on Dec. 31, 2011 and was replaced with the facilities constructed by Colorado Electric and Black Hills Colorado IPP at our Pueblo Airport Generation site. The facilities constructed by Black Hills Colorado IPP were to support an inter-company PPA with Colorado Electric. This inter-company PPA is being accounted for as a capital lease.

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•	During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 megawatts from our other generation facilities or from system purchases with reimbursement of costs by MDU.

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During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 megawatts 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.

•	Cheyenne Light renewed and received FERC approval for an agreement with Basin Electric whereby Cheyenne Light will provide 40 megawatts of capacity and energy to Basin Electric through Sept. 30, 2014.

•	Black Hills Power has a PPA with MEAN expiring April 1, 2015. Under this contract, MEAN purchases 5 megawatts of unit-contingent capacity from Neil Simpson II and 5 megawatts 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 megawatts from Neil Simpson II and up to 10 megawatts from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement.

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(1)

We have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related physical and financial transactions with BP Energy Company and/or BP Canada Energy Marketing Corp, Northern Natural Gas Company and PSCo. These commodity transactions secure natural gas supply for our regulated gas utilities. The guarantee is a continuing guarantee that may be terminated upon 30 days written notice to the counterparty.

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

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

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

•	In 2012, we had 11 gross PUD locations for 1.4 Bcfe; all were in the Williston Basin. In 2013, five of those PUD locations were drilled and we invested $3.6 million and developed 0.6 Bcfe.

•	Six gross PUD locations remain undrilled as of Dec. 31, 2013. The remaining 2012 PUD locations require approximately $2.1 million of future investment when drilled will develop approximately 0.5 Bcfe reserves in the Williston Basin.

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•	In 2013, we added 15 gross PUD locations for future Williston Basin Bakken drilling, one well in the San Juan Basin and one Piceance Mancos Shale well PUD location.

•	Analysis of offset well performance resulted in dropping one gross PUD location in the Williston Basin.

•	The number of locations, proved undeveloped reserve and future development costs in our year-end proved undeveloped reserves as of Dec. 31, 2013 were:

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

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

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*	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 Dec. 31, 2012.

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(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.

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(a)	Second quarter includes a pre-tax ceiling test impairment loss of $27 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27 million and $1.8 million, respectively.

(b)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10) million, $0.4 million, and $3.1 million after-tax in the first, second, third and fourth quarters, respectively.

(c)	Second quarter includes an after-tax ceiling test impairment loss of $17 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $18 million and $1.2 million, respectively.

(d)	Fourth quarter includes a $4.6 million after-tax make-whole provision for the early redemption of our $225 million notes.

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

ITEM 9A.	CONTROLS AND PROCEDURES

ITEM 9B.	OTHER INFORMATION

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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ITEM 11.	EXECUTIVE COMPENSATION

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

(1)

Includes 227,844 full value awards outstanding as of Dec. 31, 2013, 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, 262,741 shares of unvested restricted stock were outstanding as of Dec. 31, 2013, 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.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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(a)	$410 million of this senior unsecured note has been recorded at Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.

(b)	For 2012, this senior unsecured note was recorded by Black Hills Utility Holdings and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets. This note was redeemed on Dec. 19, 2013 with proceeds from the issuance of the Senior unsecured notes due 2023.

(c)	This senior unsecured note has been recorded by Colorado Electric and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012 and 2013.

(d)	This term loan was repaid on June 21, 2013, and replaced with the Long-term term loan due June 19, 2015. In 2012, this term loan was recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2013.

(e)	This debt has been recorded at our Power Generation segment and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets at 2013.

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(a)	Maximum terms in years reflect the amended early termination dates. These swaps were settled in 2013.

(b)	Included on the Condensed Statements of Income of the Parent is the non-cash mark-to-market gains recorded on these De-designated interest rate swaps of $30 million and $1.9 million for the twelve months ended Dec. 31, 2013 and 2012, respectively.

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

(b)	Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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3.	Exhibits

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

†	Indicates a board of director or management compensatory plan.

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

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

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

†	Indicates a board of director or management compensatory plan.