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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

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(1)	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 furnishes all of the fuel supply for the plant.

(2)	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 furnishes all of the fuel supply for the plant.

(3)

Operations at Osage were suspended Oct. 1, 2010, Ben French was suspended on Aug. 31, 2012 and Pueblo Unit #5 and Pueblo Unit #6 were suspended as of Dec. 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 insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.

(4)	Colorado Electric entered into a 20-year PPA with Black Hills Colorado IPP for 200 megawatts of power from their gas-fired plants. This PPA, accounted for as a capital lease, was effective on Jan. 1, 2012.

(5)	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.

(6)

In December 2010, Colorado Electric received a final order from the CPUC that approved the retirement of its W.N. Clark coal-fired generation facility by Dec. 31, 2013. Operations were suspended at this facility on Dec. 31, 2012. While the net book value of the W.N. Clark plant is estimated to be insignificant at the time of retirement, we would reasonably expect any remaining value to be recovered through future rates.

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(a)	With the commencement of operations of the 180 megawatt gas-fired units in Pueblo, Colo., and the low price of natural gas compared to oil, the average cost of fuel per MWh decreased.

•	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;

•	Colorado Electric’s PPA with Cargill expiring on Dec. 31, 2013, whereby Colorado Electric purchases 50 megawatts of economy energy;

•	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;

•

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 between 2013 and 2019. The purchase price related to the option is $2.55 million per megawatt. The purchase price is reduced annually by an amount of annual depreciation assuming a facility life of 35 years;

•	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 March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through March 31, 2013.

(1)

Through Black Hills Power, we own 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.

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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.

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(a)	2012 includes a $2.1 million construction savings incentive.

(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 during 2010 which was all recognized in December 2011.

(c)	Other revenue primarily consists of transmission revenue.

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(a)	Includes wind power of 199,079 MWh, 189,255 MWh and 167,520 MWh in 2012, 2011 and 2010, respectively.

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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.

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•

In October 2012, the WPSC approved Cheyenne Prairie’s construction financing rider which allows for recovery of construction financing costs from customers during the construction period in lieu of traditional AFUDC. The rider was implemented Nov. 1, 2012 and will allow Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately 60 percent of the total project cost that relates to Wyoming customers, while also saving customers money over the long-term. This will increase gross margin by approximately $5.5 million and $7.8 million in 2013 and 2014, respectively.

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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 was eliminated and the sharing mechanism was modified to 85 percent to the customer.

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In South Dakota, beginning April 1, 2010, 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, as of April 1, 2010, the ECA was modified in the rate case settlement to contain 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 beginning June 1, 2010 a similar Fuel and Purchased Power Cost Adjustment was instituted.

•	In South Dakota, we have an approved annual Environmental Improvement Cost Recovery Adjustment tariff that went into effect June 1, 2011 and 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. The revenue requirement is based on an equity return of 10.8 percent, a capital structure of 57 percent equity and 43 percent debt, and a return on rate base which is adjusted annually.

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In Colorado, we have an ECA for semi-annual increases or decreases in purchased power and fuel costs and a TCA for transmission costs. The ECA provides for the direct recovery of increased purchased power and fuel costs or the issuance of credits for decreases in purchased power, environmental generation and fuel costs. The TCA is an annual rider to the customer’s bill which allows the utility to earn an authorized return on new transmission investment and recovery of operations and maintenance costs related to transmission. Effective Jan. 1, 2012, the CPUC approved adjustments to the ECA. These adjustments allow for the recovery of transmission expenses paid to other providers, symmetrical interest, and the sharing of off-system sales margins, less certain operating costs, where the customer receives 75 percent through 2013. This sharing percentage increases to 90 percent to the customer in 2014 and thereafter.

•	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.

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(1)

Iowa Gas filed a request for a Capital Infrastructure Automatic Adjustment Mechanism with the IUB in December 2012. If approved, the adjustment could result in a revenue increase of $0.9 million in 2013 which reflects a request for recovery of costs since our prior rate case in 2010. Also if approved, an adjustment request will be required to be filed annually thereafter and subsequent filings will vary in size based on eligible infrastructure replacements and the timing of future general rate case filings. The filing is currently under review by the IUB.

(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. Black Hills Power has requested an effective date of April 1, 2013. A decision is anticipated during the third quarter of 2013. If the SDPUC has not reached a decision within 180 days, interim rates will go into effect 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 would be similar to the one approved by the WPSC 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, subject to refund. The rider will allow 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. If approved, this will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. We anticipate a final ruling by the SDPUC on this rider during the third quarter of 2013.

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Colorado. Colorado has adopted a renewable energy standard that requires 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 law limits the net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) to 2 percent and 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, and our current strategy is to incorporate renewable energy as required to comply with the standards going forward however, the 2 percent limitation may prohibit us from reaching the percentages set forth in the standards.

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Montana. Montana established a renewable portfolio standard that requires Black Hills Power to obtain a percentage of its retail electric sales in Montana from eligible renewable resources according to the following schedule: (i) 10 percent for compliance through 2014; and (ii) 15 percent for compliance year 2015 and thereafter. Utilities can meet this standard by entering into long-term purchase contracts for electricity bundled with renewable-energy credits, by purchasing the renewable-energy credits separately, or by a combination of both. The law includes cost caps that limit the additional cost utilities must pay for renewable energy and allows cost recovery from customers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards, and our current strategy is to incorporate renewable energy as required to comply with the standards.

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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. Absent a specific renewable energy mandate in South Dakota, our current strategy is to prudently incorporate renewable energy into our resource supply, seeking to minimize associated rate increases for our utility customers.

•	Wyoming. Wyoming is exploring the implementation of renewable energy portfolio standards but has not currently adopted standards.

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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.

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•	our electric utilities, Black Hills Power and Cheyenne Light. During 2012, Black Hills Power suspended operations at the 25 megawatt Ben French plant effective on Aug. 31, 2012 and announced the retirement of the Ben French plant and the 21.8 megawatt Neil Simpson I plant effective March 21, 2014 to which we sell approximately 120,000 and 130,000 tons of coal per year, respectively;

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•	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 600,000 tons of coal each year. This contract expires at the end of June 2038; and

•	certain regional industrial customers served by truck to which we sell approximately 165,000 tons of coal each year. These contracts are short-term and have a 1-3 year time range.

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

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

(b)	Reflects sale of the majority of our Williston Basin assets during 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)	Production for reserve calculations does not include volumes for NGLs.

(b)	Revisions to previous estimates for 2010 are primarily due to price changes.

(a)	Includes NGLs.

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

(a)	Includes NGLs.

(a)	Includes NGLs.

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(a)	The decrease to proved undeveloped reserves is primarily due to commodity price changes. See Note 21 in the accompanying Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further details.

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(a)

Approximately 13.3 percent (129,316 gross and 35,724 net acres), 7.3 percent (71,758 gross and 19,716 net acres) and 15.9 percent (81,944 gross and 42,796 net acres) of our undeveloped acreage could expire in 2013, 2014 and 2015, 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 during 2012.

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•	In Rapid City, S.D., we own an eight-story, 67,000 square foot office building where our corporate headquarters is located, an office building consisting of approximately 36,000 square feet, and a warehouse building and shop with approximately 30,410 square feet.

•	In Pueblo, Colo., we own approximately 22,600 square feet for a service center and approximately 25,700 square feet for a warehouse.

•	In Cheyenne, Wyo., we own a business office with approximately 13,400 square feet, and a service center and garage with an aggregate of approximately 24,400 square feet.

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•	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 and warehouse space totaling over 196,200 square feet utilized by our Gas Utilities.

•	In South Dakota, Wyoming, Colorado and Montana we own various office, service center and warehouse space totaling approximately 56,000 square feet utilized by our Electric Utilities.

•	In our service territories, we also own other offices and warehouses.

•	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 47,400 square feet of office space in Denver, Colo., of which 10,100 square feet is subleased to a third party;

•	Approximately 111,000 square feet of various office, service center and warehouse space leased by the Gas Utilities;

•	Approximately 3,600 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; and

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

•	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 Groups’ ability to operate their facilities;

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

•	Inability to recruit and retain skilled technical labor;

•	Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and gas that we sell to our retail and wholesale customers. If transmission is interrupted, our ability to sell or deliver product and satisfy our contractual obligations may be hindered;

•	Operating hazards such as leaks, mechanical problems and accidents, including explosions, affecting our natural gas distribution system which could impact public safety, reliability and customer confidence;

•	Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Natural conditions and other disasters such as wind, lightning and winter storms can cause wildfires, pole failures and associated property damage and outages;

•	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 33 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;

•	Cost of supplying or securing replacement power during scheduled and unscheduled outages;

•	The unavailability or increased cost of equipment;

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

•	Supply interruptions, work stoppages and labor disputes;

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

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

•	Weather interferences;

•	Availability and cost of fuel supplies;

•	Unexpected engineering, environmental and geological problems; and

•	Unanticipated cost overruns.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 3.	LEGAL PROCEEDINGS

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

*	Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for payment of taxes associated with the vesting of restricted stock and the exercise of stock options.

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ITEM 6.	SELECTED FINANCIAL DATA

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(1)	All years have been reclassified to include our Energy Marketing segment in Discontinued Operations. 2008 includes electric and gas utilities acquired on July 14, 2008.

(2)	Includes $938.4 million for the Aquila acquisition.

(3)	2011, 2010 and 2008 include a $27.3 million, a $9.9 million and a $61.4 million, non-cash after-tax unrealized mark-to-market loss, respectively, related to certain interest rate swaps; while 2012 and 2009 include a $1.2 million and a $36.2 million non-cash after-tax unrealized mark-to-market gain, respectively, related to certain interest rate swaps.

(4)	2012 includes a non-cash after-tax ceiling test impairment loss of $17.3 million offset by an after-tax gain on sale of $18.9 million of our Williston Basin assets (see Notes 12 and 22 of the Notes to the Consolidated Financial Statements of this Annual Report on Form 10-K.)

(5)	Includes a $27.8 million non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties taken in 2009 and a $16.9 million after-tax gain on sale of 23.5 percent ownership interest in Wygen I.

(6)	Includes a $59.0 million non-cash after-tax ceiling test impairment charge to our crude oil and natural gas properties taken in 2008.

(7)	Discontinued operations include the operations of the Energy Marketing segment in 2012, 2011, 2010, 2009 and 2008, and the assets sold in the IPP Transaction for 2009 and 2008.

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

(9)	Excludes Cheyenne Light.

(10)	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

*	On Feb. 29, 2012, we sold Enserco, our Energy Marketing segment, which resulted in this segment being classified as discontinued operations.

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In states such as South Dakota and Wyoming that currently have no legislative mandate on the use of renewable energy, we have proactively integrated cost-effective renewable energy into our generation supply based upon our expectation that there will be mandatory renewable energy standards in the future. For example, under two 20-year PPAs we purchase a total of 60 megawatts of wind energy from wind farms located near Cheyenne, Wyoming for use at Black Hills Power and Cheyenne Light;

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Colorado and Montana have legislative mandates regarding the use of renewable energy. Therefore, we aggressively pursue cost-effective initiatives with the regulators that will allow us to meet our renewable energy requirements. To the extent practical, we intend 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 CPUC approved a 29 megawatt wind turbine project, completed in the fourth quarter of 2012, in which we are permitted to rate base 50 percent ownership as part of our plan to meet Colorado’s Renewable Energy Standard. The Busch Ranch site also has significant expansion potential; 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.

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•	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;

•	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 two 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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The WPSC approved the CPCN for Cheyenne Light and Black Hills Power to construct a new jointly owned 132 megawatt generating facility in Cheyenne, Wyo. with an expected commercial operation date in the fourth quarter of 2014. Cheyenne Light and Black Hills Power also 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, and it will increase gross margin in 2013 and 2014 by approximately $5.5 million and $7.8 million, respectively. A request for a similar rider was made to the SDPUC. The SDPUC approved interim rates for that rider, effective April 1, 2013, which will increase gross margin by approximately $3.6 million and $5.6 million in 2013 and 2014, respectively. Interim rates are subject to refund until final approval is received;

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Colorado Electric completed construction of a 29 megawatt wind project as part of our plan to meet Colorado’s Renewable Energy Standards. It was placed into commercial operation on Oct. 16, 2012 and Colorado Electric owns a 50 percent interest in this wind 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 Busch Ranch wind project; and

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On July 30, 2012, Colorado Electric filed its Electric Resource Plan with the CPUC seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant, consistent with a prior CPUC order that had ordered the plant to be retired per the requirements of the Colorado Clean Air – Clean Jobs Act. The CPUC dismissed the initial filing without prejudice and directed Colorado Electric to refile the resource plan and address alternatives for not just the replacement capacity for its coal-fired W.N. Clark power plant, but also for the retirement of the aging natural gas-fired steam turbines, Pueblo Units #5 and #6. On review, the CPUC confirmed Colorado Electric’s right to own the replacement energy for the W.N. Clark power plant and extended the date to refile the resource plan to May 1, 2013.

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(a)	Income (loss) from continuing operations in 2012 includes a $17.3 million non-cash after-tax ceiling test impairment loss and an $18.9 million after-tax gain on sale of our Williston Basin assets. See Notes 12 and 22 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

(b)

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 and accordingly have been presented within Corporate of $0.6 million and $2.2 million for 2012 and 2011, respectively. See Note 23 of the Consolidated Financial Statements in this Annual Report on Form 10-K.

(c)	Includes a $1.2 million non-cash after-tax mark-to-market gain on certain interest rate swaps in 2012 and a $27.3 million non-cash after-tax mark-to-market loss in 2011 on those same certain interest rate swaps.

(d)	Income (loss) from discontinued operations, net of tax includes the activities of Enserco, our Energy Marketing segment. See Note 23 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

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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. 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 and Black Hills Power. Cheyenne Light will own 40 megawatts and Black Hills Power will own 55 megawatts of the combined-cycle unit. We have ordered all major equipment for the project and commencement of construction is expected in spring 2013. Commercial operation is expected in the fourth quarter of 2014. Project costs for plant construction and associated transmission are estimated at $222 million, with up to $15 million of construction financing, for a total of $237 million.

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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, and it will increase gross margin in 2013 and 2014 by approximately $5.5 million and $7.8 million, respectively. 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. We expect a final ruling by the SDPUC on the construction financing rider before the end of the third quarter.

•

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 certain older coal-fired and natural gas-fired facilities. In addition, the companies identified retirement dates for the older coal-fired power plants because of state and federal environmental regulations and cost to retrofit. The affected plants are listed in the table below with their operations suspension date (if applicable) and their ultimate retirement date (if identified).

•

On July 30, 2012, Colorado Electric filed its Electric Resource Plan with the CPUC seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant, which must be retired pursuant to the Colorado Clean Air – Clean Jobs Act. The CPUC dismissed the initial filing and directed Colorado Electric to refile its Electric Resource Plan by May 1, 2013 in order to address alternatives for the replacement capacity of W.N. Clark power plant, as well as the retirement of Pueblo #5 and Pueblo #6 and directed Colorado Electric to request a CPCN for any replacement capacity that Colorado Electric seeks to develop and own.

•

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 $227.9 million. We recognized a gain of $29.1 million on the sale. The portion of the sale amount not recognized as gain reduced the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.

•	Coal Mining commenced operations under its revised mine plan. Mining operations moved in August 2012, to an area with lower overburden ratios, which should reduce mining costs for the next several years.

•	In the second quarter of 2012, our Oil and Gas segment recorded a $26.9 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.

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•	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 $42.0 million unrealized mark-to-market loss on these swaps in 2011.

•	Revenues in 2011 were positively impacted by a full year of rate increases that became effective at various dates in 2010 (dollars in millions).

•	A 180 megawatt gas-fired generation plant constructed to serve Colorado Electric customers started providing energy on Jan. 1, 2012.

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•	The Wygen III generating facility commenced commercial operations on April 1, 2010. In July 2010, Black Hills Power sold a 23 percent ownership interest in the Wygen III power generation facility to the City of Gillette for $62.0 million. A gain of $6.2 million was recognized on the sale.

•

On Oct. 1, 2010, Black Hills Power suspended the operations of its 62 year old, 34.5 megawatt coal-fired Osage Power Plant located in Osage, Wyo. We now have more economical power supply alternatives available to provide for present customer energy demands. The plant’s operating permits have been retained so that full operations can be restored if needed until its’ planned retirement in March 2014.

•	Our Electric Utilities reached agreement with the DOE for smart grid funding through matching grants totaling $20.7 million, made available through the American Recovery and Reinvestment Act of 2009. We have completed 100 percent of the installations related to these meters.

•	Due to the annexation of an outlying suburb by the City of Omaha, Neb., we sold assets serving approximately 3,000 customers to Metropolitan Utilities District on March 2, 2010. We received $6.1 million in cash and recognized a $2.7 million gain on the sale in 2010.

•	In December 2010, Colorado Electric received a final order from the CPUC regarding its plan to comply with the Colorado Clean Air, Clean Jobs Act. The order approved the retirement of the utility’s 40 megawatt W.N. Clark coal-fired generation facility and granted a presumption of need for replacement of the plant.

•	A 200 megawatt gas-fired generation plant constructed for Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric started providing energy on Jan. 1, 2012.

•	We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $42.0 million in 2011 compared to a $15.2 million unrealized loss on these swaps for the same period in 2010.

•	In April 2010, we entered into a new three-year $500 million Revolving Credit Facility. The Revolving Credit Facility was used to fund working capital needs and other corporate purposes.

•	In July 2010, we completed a public offering of $200 million aggregate principal amount of senior unsecured notes due July 15, 2020. The notes were priced at par and carry an interest rate of 5.875 percent.

•	In November 2010, we entered into an equity forward offering for 4,000,000 shares. In December 2010, the underwriters exercised their over-allotment option and purchased 413,519 additional shares. We settled the equity forward instruments in November 2011.

•	In December 2010, we entered into a $100 million unsecured one-year term loan. The cost of borrowings under the loan is based on a spread of 1.375 percent over LIBOR.

•

In 2010, we recorded a $2.4 million reduction in tax expense reflecting a re-measurement of a tax position in accordance with accounting for uncertain tax positions. Approximately $2.0 million of this benefit was recorded in the Corporate segment. The re-measurement was prompted by a settlement agreement that was reached with the IRS Appeals Division primarily regarding tax depreciation method changes.

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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)	Decrease in tons of coal sold is due to the Dec.31, 2011 expiration of an agreement with PacifiCorp.

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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 increased depletion rate in 2012 is primarily driven by the high cost of wells associated with our drilling activities in the Bakken shale formation. The depletion rate for the nine months prior to the Williston Basin sale was $3.07 per Mcfe and $1.44 per Mcfe for the remaining three months of 2012 subsequent to the sale. The reduction in the full cost pool due to the sale of our Williston Basin assets should significantly decrease the depletion per Mcfe rate in 2013. See Note 22 of Notes to the Consolidated Financial Statements included in this Annual Report filed on Form 10-K.

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•	Cash earnings (income from continuing operations plus non-cash adjustments) were $46.8 million higher than prior year;

•	Net inflows from operating assets and liabilities of continuing operations of $42.2 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 $25.4 million contribution in 2012 to our defined benefit plans compared to $11.1 million in 2011; and

•	A 14.2 million increase in net cash inflows from discontinued operations in 2012 compared to 2011.

•	Cash proceeds from assets sold during 2012, including $227.9 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 $107.5 million from the sale of Enserco; and

•	In 2012, we had lower capital expenditures of $91.6 million primarily due to the completion of construction of our

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•

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 $196.0 million primarily due to our continued construction in Colorado;

•	In 2012, we repaid our $225.0 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;

•	Cash dividends on common stock of $65.3 million were paid in 2012 compared to $59.2 million paid in 2011; and

•	In 2011 we issued common stock for proceeds of $123.0 million primarily from an equity forward transaction.

•	Cash earnings (income from continuing operations plus non-cash adjustments) were $31.2 million higher than prior year;

•	An $11.1 million contribution in 2011 to our defined benefit plans compared to $30.0 million in 2010;

•	Increased inflows from operating assets and liabilities of continuing operations of $20.1 million primarily as a result of:

•	Increased cash outflows for materials, supplies and fuel primarily including purchases of natural gas at our Gas Utilities and purchases of additional supplies for generation built to support Colorado Electric customers;

•	Increased cash inflows primarily due to adjustments to our GCA at our Gas Utilities in regulatory assets and regulatory liabilities combined with inflows from energy efficiency rebates; and

•	Cash inflows from accounts receivable and other current assets primarily the result of a settlement reached with the IRS.

•	A 15.8 million increase in net cash inflows from discontinued operations in 2011 compared to 2010.

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

(b)

Includes (1) $25.4 million in 2012 for orders placed relating to Cheyenne Prairie which will commence construction in the spring of 2013 and $25.0 million for construction of our 50 percent ownership in the Busch Ranch Wind Project; (2) $65.8 million and $116.3 million in 2011 and 2010, respectively for construction of the 180 megawatt natural gas-fired generation facility at Colorado Electric, excluding transmission; (3) $31.9 million, $23.1 million and $28.0 million in new transmission projects in 2012, 2011 and 2010, respectively; and (4) $13.1 million for Wygen III construction in 2010. During 2010, we received reimbursement of $59.1 million from the joint owners of the Wygen III facility. We retained ownership of 52 percent of the Wygen III coal-fired plant that went into service in 2010.

(c)	Includes $98.2 million and $146.2 million in 2011 and 2010, respectively, for construction of the 200 megawatt natural gas-fired power generation facility at Black Hills Colorado IPP.

(d)	Approximately $37.9 million and $26.2 of the capital expenditures in 2012 and 2011, respectively, were for our drilling program in the Bakken shale formation. A majority of those assets were sold Sept. 27, 2012.

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(1)	Capital expenditures for our Electric Utilities include expenditures associated with building Cheyenne Prairie of $139.3 million and $57.7 million in 2013 and 2014, respectively.

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•	Extend the $150 million and $100 million term loans;

•	Analyze the early refinancing of our $250 million, 9 percent senior unsecured bonds that mature in May 2014; and/or

•	Review long-term financing options for the estimated $222 million Cheyenne Prairie capital project.

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(a)	In October 2012, both Moody's and S&P upgraded our outlook from Stable to Positive.

(b)	In July 2012, S&P published its updated credit review, leaving our senior unsecured credit rating of BBB- and upgraded our risk profile from strong to excellent.

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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 on long-term debt over the next five years based on a mid-year retirement date for those debt tranches expiring during the identified period: $62.9 million in 2013, $50.7 million in 2014, $39.2 million in 2015, $37.7 million in 2016, and $36.3 million in 2017. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2012.

(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 2012 and price assumptions using existing prices at December 31, 2012. Our transmission obligations are based on filed tariffs as of December 31, 2012. 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 10 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

(f)	Represents estimated employer contributions to employee benefit plans through the year 2022.

(g)	Years 1-3 include an estimated reversal of approximately $8.2 million associated with the gain deferred from the tax treatment related to the IPP Transaction and the Aquila Transaction.

(h)

Amounts in the table exclude: (1) any obligation that may arise from our derivatives, including interest rate swaps and commodity related contracts that have a negative fair value at December 31, 2012. 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 approximately 14 percent of the procurement contracts as of December 31, 2012.

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•	Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric Utilities and Gas Utilities segments resulting from commodity price changes; and

•	Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our other long-term debt instruments as described in Notes 8 and 9 of our Notes to Consolidated Financial Statements.

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(a)	Excludes unamortized premium or discount.

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

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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*	Cash and cash equivalents include cash of discontinued operations of $37.1 million, $16.0 million and $97.5 million at Dec. 31, 2011, 2010 and 2009, 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 2013, 2014, 2015, 2016, and 2017.

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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 $24.6 million.

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

(e)	Approximately $13.2 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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*	In November 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information.

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•	Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Electric Utilities and Gas Utilities segments resulting from commodity price changes; and

•	Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our other 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.

(c)	Represents the amortization of put premiums.

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(a)	These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming, both of which are priced using three-month LIBOR, matching the floating portion of the related swaps.

(b)	The maximum term in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value at the termination date. If extended, swaps totaling $100.0 million terminate in 6 years and swaps totaling $150.0 million terminate in 16 years.

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(a)	Level 1 assets and liabilities are described in Note 5.

(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)	Level 1 assets and liabilities are described in Note 5.

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(a)	Transfers into Level 3 would occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs.

(b)	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.

(c)	Previously, we utilized pricing methodologies developed by our Energy Marketing segment to value our Oil and Gas derivatives. Oil and Gas now obtains available observable inputs including quoted prices traded on active exchanges from multiple sources to value our options. Therefore, options in the Oil and Gas segment have been reclassified from Level 3 to Level 2.

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(a)	Fair value approximates carrying 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 using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

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(a)	Capital lease - plant in service represents the assets accounted for as a capital lease under the 20-year PPA between Colorado Electric and Black Hills 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. 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 their 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)	On Oct. 31, 2012, we redeemed these senior unsecured notes. See discussion below.

(b)	Variable interest rates; rates presented are as of Dec. 31, 2012.

(c)	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.

(d)	On May 15, 2012, Black Hills Power repaid these Pollution Control Refund Revenue Bonds. See discussion below.

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(a)	In June 2012, this short-term loan was extended for one year. See discussion below.

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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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(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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•	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, 2012, the restricted net assets at our Utilities Group were approximately $263.1 million.

•	As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted shareholders’ equity of at least $100.0 million.

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(a)

The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will 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 we 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. Due to this regulatory treatment, we recorded an income tax benefit in 2010 that was attributable to the 2008 through 2010 tax years. We continue to record a tax benefit consistent with the flow through method in accordance with such regulatory treatment.

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(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

(b)	Deferred taxes that were not classified as discontinued operations are now included in the Corporate segment in 2011.

(c)	See Note 23 for further information relating to discontinued operations.

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

(a)	The PPA under which the new generation facility was constructed at our Pueblo Airport Generation site by Black Hills Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing Dec. 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

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(a)	Oil and Gas includes gain on sale of the Williston Basin assets (see Note 22).

(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 8).

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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)	Electric Utilities includes gain on sale to the City of Gillette of an ownership interest in the Wygen III power generation facility. Gas Utilities includes a gain on the sale of operating assets at Nebraska Gas (see Note 22).

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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.

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(a)	Asset of VEBA

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(a)	The expected rate of return on plan assets is 7.25 percent for the calculation of the 2013 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 December 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, 2013, 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 has an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through March 13, 2013. The agreement became effective March 14, 2011.

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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.

•	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;

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•	Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light provides 40 megawatts of capacity and energy through March 31, 2013.

•	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 issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric relating to the purchase of wind turbines for the Colorado Electric wind power generation project. This guarantee will remain in effect until 91 days after satisfaction of Colorado Electric’s contractual obligations.

(3)	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.

(4)	We issued a guarantee to Colorado Interstate Gas Company for payment obligations of Black Hills Utility Holdings related to natural gas transportation, storage and services agreement.

(5)	We issued a guarantee to Cross Timbers Energy Services for the performance and payment obligation of Black Hills Utility Holdings for natural gas supply purchase.

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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.

(c)	Included in total revisions are (27,051) MMcfe due to lower commodity prices and (2,422) MMcfe for dropped PUD locations due to five year aging of reserves with negative performance revisions of (1,565) MMcfe in various basins.

•	In 2012, we sold 29 year-end 2011 PUD locations as part of an asset sale in the Williston Basin that represented $41.7 million in investment and 9.5 Bcfe reserves.

•	The San Juan Basin has three PUD locations (approximately 8.1 Bcfe and $15.1 million investment) and three PUD locations in the Piceance Basin (12.1 Bcfe and $24.7 million investment) were dropped due to low commodity pricing.

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•	Approximately 34 PUD locations were dropped for reserve aging. Of those, 32 PUD locations were in the Bear Paw Uplift (1.0 Bcfe) and two PUD locations were in the Piceance Basin (1.4 Bcfe).

•	We invested $5.7 million to develop three Williston Basin PUD locations in our remaining Williston Basin assets. PUD locations, proved reserves and future development costs associated with the Williston Basin during 2012 and at Dec. 31, 2012 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

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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.

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(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)	Second quarter includes a pre-tax ceiling test impairment loss of $26.9 million and the third and fourth quarters include a pre-tax gain on sale of the Williston Basin assets of $27.3 million and $1.8 million, respectively.

(b)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $7.8 million, $(10.1) 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 $17.3 million and the third and fourth quarters include an after-tax gain on sale of the Williston Basin assets of $17.7 million and $1.2 million, respectively.

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(a)	Includes unrealized mark-to-market gain (loss) for interest rate swaps of $3.6 million, $(5.1) million, $(24.9) million and $(0.9) million after-tax in the first, second, third and fourth quarters, respectively.

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

ITEM 9A.	CONTROLS AND PROCEDURES

•	Increased tax department resources to ensure completion and documentation of a more thorough analysis that supports our calculation of the effective tax rate and valuation of deferred tax assets and liabilities.

•	Enhanced processes and controls related to income tax accounting and reporting.

•	Utilized a quarterly “Executive Tax Dashboard” to ensure a comprehensive assessment of each quarter's tax status.

•	Implemented formal periodic meetings among the Chief Financial Officer, Controller and the tax department to ensure adequate consideration of items that may impact income tax accounting.

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ITEM 9B.	OTHER INFORMATION

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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 220,013 full value awards outstanding as of December 31, 2012, 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, 287,422 shares of unvested restricted stock were outstanding as of December 31, 2012, which are not included in the above table because they have already been issued.

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

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

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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(a)	This note was repaid on Oct. 31, 2012. This senior unsecured note had been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2011.

(b)	This senior unsecured note has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets for 2012.

(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. In 2011 $100 million of this senior unsecured note had been recorded by Black Hills Colorado IPP and was recorded as Notes receivable - affiliate, non-current on the Parent’s Condensed Balance Sheets.

(d)	This term loan has been recorded by Black Hills Utility Holdings and is recorded as Notes receivable - affiliate, current on the Parent’s Condensed Balance Sheets for 2012.

(e)	If our senior unsecured credit rating should drop below investment grade, then pricing under our credit agreements would be affected, increasing annual interest expense by approximately $1.0 million pre-tax based on our Dec. 31, 2012 debt balances.

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(a)

Under the terms of the Black Hills Wyoming project financing, Black Hills Wyoming was required to become a party to hedging agreements fixing the interest rate on a portion of the principal amount of the debt. To accomplish this, two existing swap agreements totaling $75.0 million were amended and transferred to Black Hills Wyoming so that the Parent and Black Hills Wyoming are now both jointly and severally liable for the full amount of the obligations under the swap agreements. The balance in AOCI of the Parent was frozen at that point in time and is being amortized over the remaining life of the swaps through the quarterly settlement process.

(a)	Fair value approximates carrying 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 using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

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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.