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•	Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidations and changes in competition, and (ii) general economic and political conditions, including tax rates or policies and inflation rates;

•	The timing, volatility and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets;

•	Our ability to comply, or to make expenditures required to comply, with changes in laws and regulations, particularly those relating to energy markets, taxation, safety and protection of the environment, and our ability to recover those expenditures in customer rates, where applicable;

•	Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, which may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain, or which could require closure of one or more of our generating units;

•	Changes in business, regulatory compliance and financial reporting practices and subsequent rules and regulations;

•	The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our activities to hedge our expected production of crude oil and natural gas and on our use of interest rate derivative instruments;

•	Changes in state laws or regulations that could cause us to curtail our business activities;

•	Our ability to successfully integrate and profitably operate any future acquisitions;

•	Our ability to successfully complete the sale of Enserco Energy Inc. to Twin Eagle Resource Management, LLC for net cash proceeds of approximately $160 million to $170 million, subject to working capital and other closing adjustments;

•	Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel, transportation, transmission and purchased power in our regulated utilities;

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•	Our ability to receive regulatory approval to recover in rate base our expenditures for new power generation facilities or other utility infrastructure;

•	Our ability to recover our borrowing costs, including debt service costs, in our customer rates;

•	The extent of our success in connecting natural gas supplies to gathering, processing and pipeline systems;

•	Our ability to minimize losses related to defaults on amounts due from customers and counterparties, including counterparties to trading and other commercial transactions;

•	The timing and extent of scheduled and unscheduled outages of power generation facilities;

•	Our ability to complete the permitting, construction, start-up and operation of power generating facilities in a cost-effective and timely manner;

•	Our ability to accurately estimate demand from our customers for natural gas;

•	Weather and other natural phenomena;

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Our ability to meet forecasted production volumes for our oil and gas properties, which may be dependent upon issuance by federal, state and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force and equipment, or the possibility of reductions in our drilling program resulting from the current economic climate and commodity prices, which also may prevent us from maintaining production rates and replacing reserves for our oil and gas properties;

•	The amount of collateral required to be posted from time to time in our transactions;

•	Our ability to effectively use derivative financial instruments to hedge commodity and interest rate risks;

•	Our ability to provide accurate estimates of proved oil and gas reserves, coal reserves and future production rates and associated costs;

•	Price risk due to marketable securities held as investments in employee benefit plans;

•	Our ability to successfully maintain our corporate credit rating;

•	The impact of the pending sale of Enserco Energy Inc., our non-regulated energy marketing business, on reducing our risk profile, improving our credit metrics and enhancing our ability to produce more stable cash flows and earnings;

•	Our ability to access revolving credit capacity and comply with loan covenants;

•	Capital market conditions and market uncertainties related to interest rates, which may affect our ability to raise capital on favorable terms;

•	The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock;

•	Our ability to continue paying our regular quarterly dividend;

•	Our ability to obtain permanent financing for capital expenditures on reasonable terms either through long-term debt or issuance of equity;

•	The effect of accounting policies issued periodically by accounting standard-setting bodies;

•	The accounting treatment and earnings impact associated with interest rate swaps;

•	The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

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•	The possibility that we may be required to take impairment charges under the SEC's full cost ceiling test for the accumulated costs of our natural gas and oil reserves;

•	The outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements on our financial condition or results of operations;

•	Additional liabilities for environmental conditions, including remediation and reclamation obligations, under environmental laws;

•	Our ability to successfully complete labor negotiations with labor unions with which we have collective bargaining agreements and for which we are currently in, or are soon to be in, contract renewal negotiations; and

•	The cost and effect on our business, including insurance, resulting from terrorist actions and cyber-attacks or responses to such actions or events.

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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

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

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

(3)	Operations at the Osage plant were suspended October 1, 2010 due to the availability of more economical generation alternatives.

(4)	Upon expiration of the contract with PacifiCorp in June 2012 (see below), the capacity of these units will be decreased to 80 MW.

(5)	Colorado Electric entered into a 20-year PPA with Black Hills Colorado IPP for 200 MW of power from their gas-fired plants. This PPA, accounted for as a capital lease, was effective on January 1, 2012 upon completion of construction of the plants.

(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 December 31, 2013.

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•	Black Hills Power's PPA with PacifiCorp expiring in 2023, which provides for the purchase of 50 MW of coal-fired baseload power;

•	Black Hills Power's reserve capacity integration agreement with PacifiCorp expiring in June 2012, which makes available 100 MW of reserve capacity in connection with the utilization of the Ben French CT units;

•	Colorado Electric's PPA with Black Hills Colorado IPP expiring in 2031, which provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines;

•	Colorado Electric's PPA with PSCo expiring at December 31, 2012, whereby Colorado Electric purchases 50 MW of economy energy;

•	Colorado Electric's PPA with Cargill expiring at December 31, 2013, whereby Colorado Electric purchases 50 MW of economy energy;

•	Cheyenne Light's PPA with Black Hills Wyoming expiring in August 2014, whereby Black Hills Wyoming provides 40 MW of energy and capacity from its Gillette CT;

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Cheyenne Light's PPA with Black Hills Wyoming expiring December 31, 2022, whereby Black Hills Wyoming provides 60 MW of unit-contingent capacity and energy from its Wygen I facility. The PPA includes an option for Cheyenne Light to purchase Black Hills Wyoming's ownership interest in the Wygen I facility between 2013 and 2019. The purchase price related to the option is $2.55 million per MW. This option 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 in 2028, which provides up to 29.4 MW of wind energy from the Happy Jack Wind Farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 50% of the facility's output to Black Hills Power;

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•	Cheyenne Light and Black Hills Power's Generation Dispatch Agreement requires Black Hills Power to purchase all of Cheyenne Light's excess energy; and

•	Cheyenne Light's 20-year PPA with Duke Energy expiring in 2029, which provides up to 30 MW of wind energy from the Silver Sage wind farm to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 20 MW of energy from Silver Sage to Black Hills Power.

•	MDU owns a 25% 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 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU;

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The City of Gillette owns a 23% 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 MW from our 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 their operating component of spinning reserves;

•	Black Hills Power's agreement to supply up to 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchase over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:

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

•	Cheyenne Light's agreement with Basin Electric, whereby Cheyenne Light will supply 40 MW of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 MW of capacity and energy from Basin Electric through March 31, 2013.

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(1)

Through Black Hills Power, we own 35% of a DC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western United States and eastern United States, respectively. This transmission tie, which is 65% owned by Basin Electric, provides transmission access to both the WECC region in the West and the MAPP region in the East. The transfer capacity of the tie is 200 MW from West to East, and 200 MW from East to West. Black Hills Power's electric system is located in the WECC region. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids.

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*	Off-system sales revenue had been deferred by Colorado Electric from August 2010 until December 2011, when the CPUC approved a sharing mechanism as part of the rate case settlement allowing Colorado Electric a 25% share of off-system sales operating income. Revenue in 2011 represents off-system sales from August 2010 through December 2011.

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(a)	The combined heating degree days are calculated based on a weighted average of total customers by state.

(b)	In Kansas where we have a weather normalization mechanism, normal degree days are used instead of actual degree days in computing the total number of heating degree days.

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In South Dakota, Wyoming, Colorado and Montana, we have cost adjustment mechanisms for our Electric Utilities that serve a purpose similar to the cost adjustment mechanisms in our Gas Utilities. At Cheyenne Light, our pass-through mechanism relating to transmission, fuel and purchased power costs is subject to a $1.0 million threshold: we collect or refund 95% of the increase or decrease that exceeds the $1.0 million threshold, and we absorb the increase or retain the savings for costs below the threshold as well as the 5% not collected or refunded above the threshold.

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Until April 1, 2010, South Dakota had three adjustment mechanisms: transmission, steam plant fuel (coal) and conditional ECA. The transmission and steam plant fuel adjustment clauses required an annual adjustment to rates for actual costs. Therefore, any savings or increased costs were passed on to the South Dakota customers. The conditional ECA related to purchased power and natural gas used to generate electricity. These costs were subject to calendar year $2.0 million and $1.0 million thresholds where Black Hills Power absorbed the first $2.0 million of increased costs or retained the first $1.0 million in savings. Beyond these thresholds, costs or savings were passed on to South Dakota customers through annual calendar-year filings.

•	In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect June 1, 2011 and recovers all the costs associated with plant additions.

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In Colorado, we have an ECA for increases or decreases in purchased power and fuel costs and a TCA for transmission cost adjustments. The ECA clause provides for the direct recovery of increased purchased power and fuel costs or the issuance of credits for decreases in purchased power and fuel costs. The TCA is a 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 January 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% through 2013. This sharing percentage increases to 90% to the customer in 2014.

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In Colorado, beginning in November 2010, the CPUC approved the implementation of a Purchased Capacity Cost Adjustment, the purpose of which is to recover the increase in capacity cost related to Colorado Electric's purchase power agreement with PSCo. This Purchase Capacity Cost Adjustment expired on January 1, 2012 in conjunction with expiration of the PPA with PSCo and the commencement of Colorado Electric's PPA with Colorado IPP.

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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% 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.

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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) 5% for compliance years 2008-2009; (ii) 10% for compliance years 2010-2014; and (iii) 15% 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 ratepayers for contracts pre-approved by the MTPSC. We are currently in compliance with applicable standards.

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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% of retail sales from 2011 to 2014; (ii) 20% of retail sales from 2015 to 2019; and (iii) 30% of retail sales by 2020. Of these amounts, 3% must be generated from distributed generation sources with one-half of these resources being located at customer facilities. The law limits the net annual incremental retail rate impact from these renewable resource acquisitions (as compared to non-renewable resources) to 2% 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.

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

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(1)

In December 2009, Nebraska Gas filed a rate case with the NPSC and interim rates went into effect on March 1, 2010. In August 2010, NPSC issued a decision approving an annual revenue increase of approximately $8.3 million, based on a return on equity of 10.1% with a capital structure of 52% equity effective September 1, 2010. A refund to customers for the difference between interim rates and approved rates was completed in the first quarter of 2011. The Nebraska Public Advocate has filed an appeal with the District Court which has been denied. Subsequently, the Nebraska Public Advocate has filed a notice of appeal in the Court of Appeals. This appeal is still outstanding.

(2)

In June 2010, Iowa Gas filed a request with the IUB for a $4.7 million revenue increase to recover the cost of capital investments made in our gas distribution system and other expense increases incurred since December 2008. Interim rates, subject to refund, equal to a $2.6 million increase in revenues went into effect on June 18, 2010. In August 2010, we reached a settlement with the OCA for a revenue increase of $3.4 million. This settlement agreement was modified and re-filed on January 11, 2011. The modified settlement excludes the integrity investment tracker and the three-year rate moratorium included in the original settlement agreement filed on September 1, 2010, which was not approved by the IUB. Approval from the IUB was received on February 10, 2011.

(3)

In September 2009, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the previous four years. In March 2010, the SDPUC approved a $24.1 million increase in interim rates, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC approved a final revenue increase of $15.2 million and a base rate increase of $22.0 million with an effective date of April 1, 2010. The approved capital structure and return on equity are confidential. A refund was provided to customers in the third quarter of 2010.

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(4)

In October 2009, Black Hills Power filed a rate case with the WPSC requesting a $3.8 million electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. On May 4, 2010, Black Hills Power filed a settlement stipulation agreement with the WPSC for a $3.1 million increase in annual revenues. On May 13, 2010, WPSC approved these new rates based on a return on equity of 10.5% with a capital structure of 52% equity and 48% debt. New rates went into effect on June 1, 2010.

(5)	In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase of $3.1 million.

(6)

In January 2010, Colorado Electric filed a rate case with the CPUC requesting an electric revenue increase primarily related to the recovery of rising costs from electricity supply contracts, as well as recovery for investment in equipment and electricity distribution facilities necessary to maintain and strengthen the reliability of the electric delivery system in Colorado. On August 5, 2010, the CPUC approved a settlement agreement for $17.9 million in annual revenues with a return on equity of 10.5% and a capital structure of 52% equity and 48% debt. New rates were effective August 6, 2010.

(7)

In April 2011, Colorado Electric filed a request with the CPUC for an annual revenue increase of $40.2 million, or 18.8%, to recover costs and a return on capital associated with the 180 MW generating facility that commenced commercial operation on January 1, 2012, associated infrastructure assets and other utility expenses, including the PPA with Colorado IPP. On December 22, 2011, the CPUC issued an order approving an annual base rate increase of $10.5 million with a rate of return ranging from 9.8% to 10.2% with a capital structure of 49.1% equity and 50.9% debt. New rates were effective January 1, 2012. In addition, approximately $17.5 million of other costs including fuel, purchased power and new transmission will be recovered through normal cost adjustment mechanisms.

(8)	On December 1, 2011, Cheyenne Light filed requests for electric and natural gas revenue increases with the WPSC to recover investment in infrastructure and other costs. Cheyenne Light is seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue.

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•	Oil and Gas

•	Power Generation

•	Coal Mining

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(a)	Included in the total revisions are (23.6) Bcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2.3 Bcfe in various basins. Revisions due to cost and commodity pricing were less than 1% of total reserve quantities.

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

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

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

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(a)	Revisions to previous estimates for 2009 primarily due to price changes.

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

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Approximately 4.7% (52,061 gross and 10,492 net acres) and 15.8% (125,063 gross and 35,120 net acres) and 6.5% (59,832 gross and 14,362 net acres) of our net undeveloped acreage could expire in 2012, 2013 and 2014, respectively, if production is not established on the leases or further action is not taken to extend the associated lease terms. Decisions on extending leases are based on expected exploration or development potential under the prevailing economic conditions.

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(1)	On January 18, 2011, we sold our ownership interest in the partnerships that owned the Glenns Ferry and Rupert Cogeneration facilities.

(2)	The plant commenced commercial operation on January 1, 2012. Black Hills Colorado IPP has the obligation to operate this facility under the 20-year PPA which is accounted for as a capital lease.

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•	Our regulated electric utilities, Black Hills Power and Cheyenne Light;

•	The 362 MW Wyodak power plant owned 80% by PacifiCorp and 20% by Black Hills Power under which PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustments for planned outages. This contract expires at the end of December 2022;

•	The 110 MW Wygen III power plant owned 52% by Black Hills Power, 25% by MDU and 23% by the City of Gillette;

•	The 90 MW non-regulated mine-mouth power plant, Wygen I, owned 76.5% by Black Hills Wyoming and 23.5% by MEAN; and

•	Certain regional industrial customers served by truck.

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

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

•	Approximately 47,430 square feet of office space in Denver, Colorado; and

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

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*	Excludes 44 Energy Marketing employees of our discontinued operations subsidiary, Enserco, due to the proposed sale of Enserco.

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ITEM 1A.	RISK FACTORS

•	Commodity prices can often be volatile. A decline in oil and natural gas price volatility could affect our revenues and returns from our trading activities at Enserco, which tend to increase when markets are volatile.

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Derivative instruments are used in conjunction with our trading activities to limit a portion of the potential adverse effects resulting from changes in commodity prices and foreign exchange rates. Even though they are closely monitored by Management, our hedging and trading activities can result in losses. Depending upon regulations adopted by the CFTC, we could be required to post additional collateral with our dealer counterparties for our commitments. Such a requirement could have a significant impact on our ability to execute derivative transactions and on cash flow.

•	The operations of Enserco rely on storage and transportation assets owned by third parties to satisfy their obligations. We depend on pipelines and other storage and transportation facilities owned by third parties to satisfy our delivery obligations under contracts to buy and sell natural gas, crude oil, coal and other commodities, which are settled by physical delivery.

•	Enserco may be subject to increased regulation, which may limit position limits and opportunity for various transactions.

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The global financial situation has affected our counterparty credit risk, and as a consequence the creditworthiness of many of our contractual counterparties (particularly financial institutions) has deteriorated. Additionally, economic conditions may cause increased late payments and uncollectible accounts. Even though we have established guidelines, controls and limits to manage and mitigate credit risk and this is monitored closely by management, to the extent economic conditions cause our credit exposure to contractual counterparties to increase materially, such increased exposure could have a material adverse effect on Energy Marketing's results of operations, liquidity and financial position.

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•	Our inability to obtain required governmental permits and approvals;

•	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;

•	Lower than anticipated increases in the demand for utility services in our target markets;

•	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.

•	Delay in, and restrictions imposed as part of, any required governmental or regulatory approvals;

•	The loss of management or other key personnel;

•	The diversion of our management's attention from other business segments; and

•	Integration and operational issues.

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•	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;

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

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

•	Weather interferences;

•	Unexpected engineering, environmental and geological problems; and

•	Unanticipated cost overruns.

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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' 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.

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•	Labor relations. Approximately 33% of our employees are represented by a total of six collective bargaining agreements.

•	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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We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks and other disruptive activities of individuals or groups.  Our generation, transmission and distribution facilities, fuel storage facilities, information technology systems and other infrastructure facilities and systems and physical assets, could be direct targets of, or indirectly affected by, such activities.  Terrorist acts or other similar events could harm our businesses by limiting their ability to generate, purchase or transmit power and by delaying their development and construction of new generating facilities and capital improvements to existing facilities.  These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets, and could adversely affect our operations by contributing to disruption of supplies and markets for natural gas, oil and other fuels.  They could also impair our ability to raise capital by contributing to financial instability and lower economic activity.

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We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite our implementation of security measures, all of our technology systems are vulnerable to disability, failures or unauthorized access, including cyber-attacks.  If our technology systems were to fail or be breached and be unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could have material adverse effect on our financial results.

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The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs.  These types of events could materially adversely affect our financial results.  In addition, these types of events could require significant management attention and resources, and could adversely affect our reputation among customers and the public.

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A disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system (such as severe weather or a generator or transmission facility outage, pipeline rupture, or a sudden significant increase or decrease in wind generation) within our system or within a neighboring system. Any such disruption could have a material impact on our financial results.

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•	Energy Policy Act of 2005 and the repeal of the PUHCA;

•	Industry consolidation;

•	Consumer demands;

•	Transmission constraints;

•	Renewable resource supply requirements;

•	Resistance to the siting of utility infrastructure or to the granting of right-of-ways;

•	Technological advances; and

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•	Greater availability of natural gas-fired power generation, and other factors.

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

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ITEM 3.	LEGAL PROCEEDINGS

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

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*	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 restated 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)	Revenues have been restated to reflect elimination of certain inter-company transactions with our rate regulated operations (see Note 1 of the Notes to the Consolidated Financial Statements of this Annual Report on Form 10-K).

(4)	2011, 2010 and 2008 include a $27.3 million, a $9.9 million and a $61.4 million, after-tax unrealized non-cash mark-to-market loss, respectively, related to certain interest rate swaps; while 2009 includes a $36.2 million after-tax unrealized non-cash mark-to-market gain related to certain interest rate swaps.

(5)	Includes a $27.8 million after-tax non-cash 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% ownership interest in Wygen I.

(6)	Includes a $59.0 million after-tax non-cash 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 2011, 2010, 2009, 2008 and 2007, and the assets sold in the IPP Transaction for 2009, 2008 and 2007.

(8)	During November 2011, we issued 4.4 million shares of common stock and during February 2007, we issued 4.2 million shares of common stock, which diluted our earnings per share in subsequent periods.

(9)	The PPA between Colorado Electric and Black Hills Colorado IPP is accounted for as a capital lease. This table reflects owned capacity by the Electric Utilities and Power Generation.

(10)	2007 includes 825 MW which have been reported as "Discontinued operations."

(11)	Excludes Cheyenne Light.

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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

*	In January 2012, we entered into a Stock Purchase Agreement to sell Enserco, our Energy Marketing segment, which resulted in the reporting of this segment as discontinued operations. The sale transaction is expected to be completed during the first quarter of 2012.

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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 MW of wind energy from wind farms located near Cheyenne, Wyoming for use at Black Hills Power and Cheyenne Light;

•

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 MW wind turbine project in which we are permitted to rate base 50% ownership as part of our plan to meet Colorado's Renewable Energy Standard expected to be completed by the end of 2012; 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;

•

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, continuing our participation in the Bakken oil shale play 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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•	Cheyenne Light and Black Hill Power filed a joint CPCN requesting approval to construct a new 132 MW generating facility;

•	Colorado Electric completed construction of a 180 MW generating facility, which was placed into commercial operation on January 1, 2012;

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•	Although CPUC issued an order approving the retirement of our W.N. Clark coal-fired generation facility in order to comply with the Colorado Clean Air-Clean Jobs Act for Colorado Electric, the CPUC has not yet approved plans proposed to replace the facility; and

•	The CPUC approved construction of a 29 MW wind farm, of which Colorado Electric will own 50%, as part of our plan to meet Colorado's Renewable Energy Standards and Colorado Electric expects to file an energy resource plan to address additional renewable energy required to comply with Colorado's renewable energy standards in the second quarter of 2012.

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(a)	2010 revenue has been restated to eliminate certain inter-company revenue previously not eliminated. This change did not have an impact on our gross margin or net income. See Note 1 of 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. See Note 23 of the Consolidated Financial Statements in this Annual Report on Form 10-K.

(c)	Income (loss) from discontinued operations, net of tax includes the activities of Enserco, our Energy Marketing segment, for 2011, 2010 and 2009 and the IPP Transaction for 2009. See Note 23 of 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 five utility jurisdictions during 2010. Consequently, year-to-date revenues have been positively impacted for rates that were not in effect in the prior periods.

•	Construction of gas-fired generation to serve Colorado Electric customers was completed and the plant was placed in service on January 1, 2012. The 180 MW generation project cost approximately $230 million;

•

On April 28, 2011, Colorado Electric filed a request with the CPUC for a revenue increase of $40.2 million to recover costs and a return associated with the 180 MW generation project and other utility infrastructure assets and expenses, including PPA costs associated with the 200 MW Colorado IPP generation facility. On December 22, 2011, the CPUC issued an order approving an annual base rate increase of $10.5 million with a rate of return ranging from 9.8% to 10.2% with a capital structure of 49.1% equity and 50.9% debt. The CPUC approved additional costs to be recovered through rate adjustment mechanisms of approximately $17.5 million. New rates were effective January 1, 2012;

•	On December 1, 2011, Cheyenne Light filed requests for electric and natural gas revenue increases with the WPSC to recover investments in infrastructure and other costs. Cheyenne Light is seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue;

•

On November 1, 2011, Cheyenne Light and Black Hills Power filed a joint request with the WPSC for a certificate of public convenience and necessity to construct and operate a new $237 million natural gas-fired electric generation facility and related gas and electric transmission in Cheyenne, WY. The proposed facility will include construction of one simple-cycle, 37 MW combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 MW unit that will be jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Light will own 40 MW and Black Hills Power will own 55 MW of the combined cycle unit. Pending WPSC approval, commercial operation would commence in 2014. A hearing with the WPSC is scheduled in July 2012;

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•	In June 2011, the SDPUC approved an Environmental Improvement Adjustment tariff for Black Hills Power. The Environmental Improvement Adjustment, which was implemented to recover Black Hills Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect on June 1, 2011 with an annual revenue increase of $3.1 million;

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On August 12, 2011, Colorado Electric received approval from the CPUC to rate base 50% ownership in a 29 MW wind turbine project as part of its plan to meet Colorado's Renewable Energy Standard. The CPUC authorized us to conduct a competitive solicitation for ownership of the other 50% of the project under which a partner was selected in December 2011 and a Renewable Energy Purchase Agreement and Participation agreement was executed on December 22, 2011. Colorado Electric's share of this project is expected to cost approximately $26.5 million. It is expected to begin serving Colorado Electric customers no later than December 31, 2012; and

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On March 14, 2011, Colorado Electric filed a request for a CPCN to construct a third utility-owned 88 MW natural gas-fired turbine with an approximate cost of $102.0 million, excluding transmission. This CPCN request was filed in accordance with a December 2010 CPUC order. This order approved the retirement of the W.N. Clark coal-fired power plant under the Colorado Clean Air-Clean Jobs Act and granted a presumption of need for a portion of a third utility-owned turbine at the Pueblo Airport Generation Station. A settlement with some of the intervenors was reached and a settlement hearing occurred on October 25, 2011. On December 14, 2011, an administrative law judge issued a recommendation to deny Colorado Electric's request and the terms of the settlement agreement. Colorado Electric submitted an exception filing on January 10, 2012, and an initial decision from the CPUC is expected in mid-2012.

•

In January 2012, we entered into a definitive agreement to sell the outstanding stock of Enserco Energy, Inc., our Energy Marketing segment. Net cash proceeds are expected to total approximately $160 million to $170 million, subject to working capital and other closing adjustments. The sale is subject to customary regulatory approvals and is expected to close in the first quarter of 2012. The activities of the Energy Marketing segment have been reclassified to discontinued operations;

•	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 January 1, 2012. The 200 MW project cost approximately $261 million;

•	Three test wells as part of our Oil and Gas segment's Mancos shale horizontal drilling program in the San Juan and Piceance Basins have been completed and are on production. Production test results and reserve estimates are encouraging; and

•	In January 2011, we sold our ownership interests in the partnerships that owned the Idaho generating facilities for $0.8 million and recorded a gain of $0.8 million.

•	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 mark-to-market loss on these swaps for the same period in 2010;

•	In November 2011, the Equity Forward Agreements were settled by issuing 4,413,519 shares of Black Hills Corporation common stock in return for net cash proceeds of $119.6 million;

•	In September 2011, we extended our $100.0 million term loan under the existing terms for two years; and

•	In June 2011, we entered into a $150 million one year, unsecured, single draw, term loan. The cost of borrowing under this term loan is based on a spread of 1.25% over LIBOR.

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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 five utility jurisdictions during 2010. Consequently, year-to-date revenues were positively impacted for rates that were not in effect in the prior periods.

•	Construction of a 180 MW gas-fired generation to serve Colorado Electric customers moved forward to start providing energy by January 1, 2012. Expenditures were approximately $164.4 million through December 31, 2010;

•	The Wygen III generating facility commenced commercial operations on April 1, 2010. In July 2010, Black Hills Power sold a 23% 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 October 1, 2010, Black Hills Power suspended the operations of its 62 year old, 34.5 MW coal-fired Osage Power Plant located in Osage, Wyoming. We now have more economical power supply alternatives available to provide for present customer energy demands; however, the plant's operating permits have been retained so that full operations can be restored if needed;

•	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. As of December 31, 2010, we have completed 100% of the installations related to these meters;

•	Due to the annexation of an outlying suburb by the City of Omaha, NE, 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 the first quarter of 2010; and

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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 42 MW W.N. Clark coal-fired generation facility and granted a presumption of need for replacement of the plant. The utility proposed to construct a third 88 MW natural gas-fired turbine at the site of our Pueblo Airport Generation Station.

•	Construction of a 200 MW gas-fired generation at Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric moved forward to start providing energy by January 1, 2012. Expenditures on the project were $162.6 million through December 31, 2010;

•	The first quarter of 2009 included a $16.9 million after-tax gain at our Power Generation segment on the sale to MEAN of a 23.5% ownership interest in the Wygen I power generation facility; and

•	The first quarter of 2009 included a $27.8 million after-tax non-cash ceiling test impairment charge due to a write-down in value of our natural gas and crude oil properties resulting from low quarter-end prices for the commodities at our Oil and Gas segment.

•	We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $15.2 million in 2010 compared to a $55.7 million unrealized gain on these swaps for the same period in 2009;

•	In April 2010, we entered into a new three-year $500 million Revolving Credit Facility. The Revolving Credit Facility will be 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%;

•	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% over LIBOR; and

•	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)	2011 reflects a major overhaul and an unplanned outage at the PacifiCorp-operated Wyodak plant.

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(a)	Net of hedge settlement gains/losses

(b)	Exclusive of gas liquids

*

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 2011 is primarily driven by the high cost of wells associated with our drilling activities in the Bakken shale formation. The 2009 rate was particularly impacted by a lower asset base as a result of previous asset impairment charges. This impact was partially offset by persistent low product prices during the year, which resulted in lower oil and gas reserve quantities.

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•	We incurred a $42.0 million unrealized mark-to-market loss in 2011 related to certain interest rate swaps that are no longer designated as hedges for accounting purposes compared to a $15.2 million unrealized mark-to-market loss in 2010; and

•	Corporate was allocated costs of $3.4 million originally allocated to our Energy Marketing segment in 2011 which could not be included in discontinued operations compared to $3.5 million in 2010.

•	We incurred a $15.2 million unrealized mark-to-market loss in 2010 related to certain interest rate swaps that are no longer designated as hedges for accounting purposes compared to an unrealized mark-to-market gain of $55.7 million in 2009;

•	Net interest expense increased $1.4 million primarily due to interest settlements of the de-designated interest rate swaps;

•	The effective tax rate for 2010 was favorably impacted due to a re-measurement of a previously recorded uncertain tax position prompted by a settlement agreement with the IRS relating primarily to depreciation method changes; and

•	Corporate was allocated costs of $3.5 million originally allocated to our Energy Marketing segment in 2010 which could not be included in discontinued operations compared to $3.8 million in 2009.

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(a)	Activity of Coal marketing commenced June 1, 2010 and Power and Environmental marketing commenced late in the third quarter of 2010.

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*	The Revolving Credit Facility was replaced when we entered into a new Revolving Credit Facility on February 1, 2012. See Credit Facilities and Long-Term Debt below.

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

(2)

Includes (a) $13.1 million and $119.9 million for Wygen III construction in 2010 and 2009, respectively. During 2010 and 2009, we received reimbursement of $59.1 million and $58.0 million from the joint owners of the Wygen III facility. We own 52% of the Wygen III coal-fired plant that went into service on April 1, 2010; (b) $65.8 million, $116.3 million and $48.1 million in 2011, 2010 and 2009, respectively for construction of the 180 MW natural gas-fired generation facility at Colorado Electric, excluding transmission and (c) $23.1 million, $28.0 million and $21.1 million in new transmission projects in 2011, 2010 and 2009, respectively.

(3)	Includes $98.2 million, $146.2 million and $16.4 million in 2011, 2010 and 2009, respectively, for construction of the 200 MW natural gas-fired power generation facility at Colorado IPP.

(1)	Capital expenditures for our Electric Utilities include expenditures associated with our Black Hills Power, Cheyenne Light and Colorado Electric energy resource plans.

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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: $79.2 million in 2012, $70.9 million in 2013, $51.2 million in 2014, $39.6 million in 2015 and $37.9 million in 2016. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2011.

(c)

Unconditional purchase obligations include the energy and capacity costs associated with our power purchase agreements, the capacity and certain transmission, gas purchase and gas transportation and storage agreements. The energy charge under the PPA and the commodity price under the gas purchase contract are variable costs, which for purposes of estimating our future obligations, were based on costs incurred during 2011 and price assumptions using existing prices at December 31, 2011. Our transmission obligations are based on filed tariffs as of December 31, 2011. A portion of our gas purchases are purchased under evergreen contracts and therefore, for purposes of this disclosure are carried out for 60 days.

(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 Oil and Gas, Coal Mining, Electric Utilities and Gas Utilities 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 2021.

(g)	Years 1-3 include an estimated reversal of approximately $10.2 million associated with the gain deferred from the tax treatment related to the IPP Transaction and the Aquila Transaction. The income tax refund receivable was reversed as a result of an agreement reached with the IRS in 2010.

(h)

Amounts in the above 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, 2011. These amounts have been excluded as it is impracticable 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 these fluctuations. The impact of these hedges is not included in the above table. (3) The obligations presented above do not include inter-company transactions. (4) The table above does not include obligations of our Energy Marketing segment. See Discontinued Operations discussion below.

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•	Cash earnings (net income plus adjustments to reconcile income) 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 $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 PGA 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.

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•	Cash earnings (net income plus adjustments to reconcile income) increased $15.2 million;

•	A $30.0 million contribution in 2010 to our defined benefit plans compared to $16.9 million in 2009;

•	Outflows from operating assets and liabilities of $124.5 million as a result of:

•	Materials, supplies and fuel used funds of $37.1 million primarily relating to decreases in the Gas Utilities gas storage in 2009 as compared to 2010; and

•	Outflows of $23.9 million from higher use of funds in regulatory assets primarily related to energy efficiency rebates.

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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 and Gas Utilities segments resulting from commodity price changes; and

•	Interest rate risk associated with our variable rate credit facilities and our project financing floating rate debt 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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(a)	The fair value of energy marketing positions consists of the mark-to-market values of derivative assets/liabilities and market value adjustments to natural gas inventory that has been designated as a hedged item as part of a fair value hedge, as follows (in thousands):

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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, $97.5 million and $94.7 million at December 31, 2011, 2010, 2009 and 2008, 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, $0.2 million, $0.2 million, $0.2 million, and $0.2 million for 2012, 2013, 2014, 2015, and 2016, respectively.

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•

Commodity derivatives - Oil and Gas: Our derivative option contracts are valued under the income approach using option pricing models based on data either readily observable in public markets, derived from public markets or provided by counterparties who regularly trade in public markets. Our derivative swap contracts are valued under the income approach using a discounted cash flow model based on data either readily observable or derived from public markets.

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Commodity derivatives - Utilities: Our gas hedge portfolio for our Utilities generally consists of futures, basis swaps and option contracts. The fair value of these financial instruments is estimated based on market trading information, where available. Absent published market values for an instrument or other asset, management uses observable market data to arrive at its estimates of fair value. These contracts have been classified as Level 2 measurements.

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Interest rate swaps: The fair value of our interest rate swap contracts are determined using standard valuation models. The significant inputs used in these models are readily available in public markets or can be derived from observable market transactions and; therefore, these derivative contracts have been classified as Level 2. Inputs used in these standard valuation models include the applicable market forward rates and discount rates.

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*	On November 1, 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 and Gas Utilities segments resulting from commodity price changes; and

•	Interest rate risk associated with variable rate credit facilities and project financing floating rate debt and our derivative instruments as described in Notes 4, 5, 8 and 9.

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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)	The maximum term in years reflects the amended mandatory early termination dates. If the mandatory early termination dates are not extended, the swaps will require cash settlement based on the swap value of the termination date. When extended, de-designated swaps totaling $100.0 million terminate in 7 years and de-designated swaps totaling $150.0 million terminate in 17 years.

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(a)	Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.

(b)	Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

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

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Black Hills Power also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the tie is 400 MW - 200 MW West to East and 200 MW from East to West. Black Hills Power is committed to pay its proportionate share of the additions and replacements to and operating and maintenance expenses of the transmission tie.

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Black Hills Power own 52% of its Wygen III coal-fired generation facility which commenced commercial operation on April 1, 2010. MDU and the City of Gillette each owns an undivided ownership interest in the Wygen III generation facility and are obligated to make payments for costs associated with administrative services and proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.

•	Black Hills Wyoming owns 76.5% of its Wygen I Plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for 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)	Variable interest rates, rates presented are as of December 31, 2011.

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*	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 grant date fair value of the 2011 awards was $5.80 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.6% risk free interest rate, 29.0% expected price volatility, 4.6% 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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In connection with the Aquila Transaction, the CPUC, NPSC, IUB and KCC approved orders or settlement agreements providing that, among other things, (i) our utilities in those jurisdictions cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and (ii) neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. Covenants within Cheyenne Light's financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. In addition to the restrictions described above, each state in which we conduct utility operations imposes restrictions on affiliate transactions, including inter-company loans. Additionally, our utility subsidiaries are generally limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may be subject to further restrictions under the Federal Power Act. As of December 31, 2011, the restricted net assets at our Electric and Gas Utilities were approximately $61.5 million.

•	Pursuant to a covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted assets of $100.0 million. In addition, Black Hills Wyoming holds $9.3 million of restricted cash in accordance with project financing requirements. Black Hills Non-regulated Holdings is the parent of Black Hills Electric Generation, which is the parent of Black Hills Wyoming.

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*

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 that was attributable to the 2008 through 2010 tax years. For years prior to 2008, we did not record a regulatory asset for the repairs deduction as the tax benefit was not flowed through to customers.

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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, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

(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, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

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

(a)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).

(b)	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)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).

(b)	Includes a gain on sale to MEAN of an ownership interest in the Wygen I power generation facility (see Note 22).

(c)	As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets (see Note 12).

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*	The expected rate of return on plan assets changed to 7.25% for the calculation of the 2012 net periodic pension cost.

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•	Black Hills Power's PPA with PacifiCorp, expiring December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp's system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants.

•	Black Hills Power has a firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023. The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp.

•	Cheyenne Light's PPA with Duke Energy's Happy Jack wind site, expiring September 3, 2028, provides up to 30 MW of wind energy from Happy Jack to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 50% of the facility output to Black Hills Power.

•	Cheyenne Light's PPA with Duke Energy's Silver Sage wind site, expiring September 30, 2029, for up to 30 MW of wind energy. Under a separate intercompany agreement, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to Black Hills Power.

•	Colorado Electric's PPA with PSCo expiring December 31, 2012, whereby Colorado Electric purchases 50 MW of economy energy.

•	Colorado Electric's PPA with Cargill expiring December 31, 2013, whereby Colorado Electric purchases 50 MW of economy energy.

(a)	This PPA with PSCo expired on December 31, 2011 and was replaced with the facilities constructed by Colorado Electric at our Pueblo Airport Generation site and the facilities constructed by Black Hills Colorado IPP to support a new PPA with Colorado Electric.

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

•

During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, Black Hills Power will also provide the City of Gillette their operating component of spinning reserves;

•	Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light provides 40 MW of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 MW of capacity and energy from Basin Electric through March 13, 2013. The agreements became effective March 14, 2011;

•	Black Hills Power has a PPA with MEAN expiring April 1, 2015. Under this contract, MEAN purchases 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III; and

•	Black Hills Power has a PPA with MEAN expiring May 31, 2023. This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III is 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 four guarantees to GE for payment obligations arising from contracts to purchase four LM6000 gas turbines for Black Hills Colorado IPP. These are continuous guarantees which will terminate upon settlement of all obligations.

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(3)	We have issued two guarantees to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers. These are continuing guarantees which will terminate upon settlement of all obligations.

(4)	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 satisfaction of Colorado Electric's contractual obligations.

(5)	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.

(6)	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 agreements.

(7)	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 (NGL's).

(b)	Included in the total revisions are (23.6) Bcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2.3 Bcfe in various basins. Revisions due to cost and commodity pricing were less than 1% Bcfe.

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•

Companies are required to include a narrative disclosure of the total quantity of PUDs at year end, any material changes in PUDs during the year, and investment and progress made in converting the PUDs during the year. In 2011, we invested approximately $18.9 million to drill and develop 9 PUD locations from our 2010 inventory totaling approximately 4.7 Bcfe in proved developed reserve recognition. 100% of the PUD development in 2011 was in the Williston Basin which resulted in approximately 13 additional PUDs (4.6 net Bcfe) added to our year-end 2011 reserves. Additional PUDs were added in the Piceance (3 gross locations, 12.0 net Bcfe) and San Juan (2 gross locations, 7.5 net Bcfe) basins following 2011 drilling in those basins.

•	Approximately 23.6 Bcfe were dropped from the proved reserves in 2011 due to five year aging of the PUDs. This drop was primarily in the Piceance (21.2 Bcfe, 17 gross locations, $34.7 million future investment), Bear Paw Uplift (0.5 Bcfe, 17 gross locations, $0.8 million future investment), and Wind River Basin (2.0 Bcfe, 25 gross locations, and $3.6 million future investment).

•	As of December 31, 2011, PUD locations, proved reserves and future development costs associated with certain locations are as follows:

•	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.

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*	Includes pre-tax ceiling test impairment charges of $43.3 million in 2009.

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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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(a)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated. See Note 1.

(b)	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively.

(c)	Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 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

•	The assessment of the impact of certain non-routine transactions on the accuracy of our year-end income tax provision was not effective.

•	Tax resources were not sufficient to effectively prepare and review the analysis of tax accounts.

•	Communication between the tax department and the Controller organization was not effective to ensure income tax accounting consequences were adequately considered.

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•	Increase 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.

•	Implement 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 173,989 full value awards outstanding as of December 31, 2011, 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, 278,155 shares of unvested restricted stock were outstanding as of December 31, 2011, 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)	In order to restructure debt and equity capitalization at our utilities, 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.

(b)	In order to restructure debt and equity capitalization at our utilities, $100.0 million of 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.

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*

Under the terms of the Black Hills Wyoming project financing, Black Hill 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 were amended 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.  As of January 15, 2010, the mark to market liability associated with the two swaps with a notional value of $75.0 million was transferred from the Parent to Black Hills Wyoming.  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.

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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.