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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 or foreign exchange 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 arising from the enactment of the Energy Policy Act of 2005 and subsequent rules and regulations promulgated thereunder;

•	The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our energy marketing activities and to hedge our expected production of 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 independent power production or exploration and production activities;

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

•	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;

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

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•	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, currency exchange rate 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;

•	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;

•	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;

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

•	Our ability to successfully complete labor negotiations with labor unions with whom 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 or responses to such actions or events.

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ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

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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 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 PSCo expiring at the end of 2011, whereby Colorado Electric purchases a majority of its power. The contract provides for 300 MW of capacity and energy in 2011;

•	Colorado Electric's 20-year PPA with Black Hills Colorado IPP, beginning on January 1, 2012 and expiring in 2031, which will provide 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines, which are currently under construction;

•	Cheyenne Light's PPA with Black Hills Wyoming expiring in August 2011 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 which is equivalent to the estimated initial per MW price of new construction of the Wygen III facility. This 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;

•	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, provides 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.

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In conjunction with MDU's April 2009 purchase of a 25% ownership interest in Wygen III, an agreement to supply 74 MW of capacity and energy through 2016 was modified. The sales to MDU have been integrated into Black Hills Power's control area and are considered part of our firm native load. MWs from the Wygen III unit are deemed to supply a portion of the required 74 MW. During periods of reduced production at Wygen III, 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;

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Black Hills Power's agreement with the City of Gillette to dispatch the City of Gillette's 23% of Wygen III's net generating capacity for the life of the plant. Upon the City of Gillette's July 2010 purchase of a 23% ownership interest in Wygen III, a seven year PPA with the City of Gillette that went into effect in April 2010, was terminated. The City of Gillette's 23 MW of Wygen III capacity has been integrated into Black Hills Power's control area and are considered part of our firm native load. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we 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 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 capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:

•	Black Hills Power's five-year PPA with MEAN which commenced in May 2010 whereby MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III; and

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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. The agreements become effective on March 14, 2011, and terminate prior agreements under which Cheyenne Light supplies Basin Electric with 80 MW of energy and capacity, and Basin Electric supplies Cheyenne Light with 80 MW of energy and capacity.

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South Dakota. South Dakota has adopted a renewable portfolio objective that encourages 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 renewable resources with one-half of the renewable 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. Our current strategy is to incorporate renewable energy as required to comply with the standards.

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(1)

On December 1, 2009, Nebraska Gas filed with the NPSC a $12.1 million rate case requesting a gas revenue increase to recover operating costs and distribution system investments. The proposed increase in revenue was approximately 6.5%. Interim rates, subject to refund for the entire amount of the proposed increase, went into effect on March 1, 2010. On August 18, 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 plan for refund has been approved by the NPSC. An appeal was filed by the OCA relating to the entire rate case decision. However, the NPSC denied this appeal. Subsequently, the OCA filed an appeal in September 2010 appealing a portion of the Commission's order addressing our affiliate transactions. The appeal is still outstanding.

(2)

On June 8, 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)

On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of Black Hills Power's open access transmission tariff, and increased the utility's annual transmission revenue requirement by approximately $3.8 million. The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt. New annual rates went into effect on January 1, 2009.

(4)

On September 30, 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 past 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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(5)

On October 19, 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.

(6)

On January 6, 2010, Colorado Electric filed a rate case with CPUC requesting a $22.9 million electric revenue increase to recover increased operating expenses associated with 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.

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•	Oil and Gas;

•	Power Generation;

•	Coal Mining; and

•	Energy Marketing.

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(1)	We are currently constructing two 100 MW combined-cycle gas-fired power generation facilities in Colorado. These facilities are expected to be completed by December 31, 2011.

(2)	In January 2009, we sold a 23.5% ownership interest in this plant to MEAN. See Note 22 of Notes to our Consolidated Financial Statements for further description of the transaction.

(3)	On January 18, 2011, we sold our ownership interest in the partnerships which owns the Glenns Ferry and Rupert Cogeneration facilities.

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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;

•	PacifiCorp for the Dave Johnston power plant located near Casper, Wyoming and served by rail;

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

•	Our 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 62,160 square feet of office space in Omaha, Nebraska;

•	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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ITEM 1A.	RISK FACTORS

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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 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 and our coal-fired 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.

•	The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals;

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•	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 Gas Utilities purchase 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 Gas Utilities' ability to operate their facilities.

•	Breakdown or failure of equipment or processes.

•	Inability to recruit and retain skilled technical labor.

•	Labor relations. Approximately 33% of our employees are represented by a total of six collective bargaining agreements. We are currently in contract renewal negotiations on two of these agreements. Three separate arbitration proceedings have been initiated by the respective union locals concerning changes we made to our pension plans.

•	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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•	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

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

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ITEM 1B.	UNRESOLVED STAFF COMMENTS

ITEM 3.	LEGAL PROCEEDINGS

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

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ITEM 6.	SELECTED FINANCIAL DATA

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•	Provide stable long-term rates for customers and increase earnings by efficiently planning, constructing and operating rate-base power generation facilities needed to serve our electric utilities;

•	Proactively integrate alternative and renewable energy into our utility energy supply while mitigating and remaining mindful of customer rate impacts;

•	Expand utility operations through selective acquisitions of electric and gas utilities consistent with our regional focus and strategic advantages;

•	Build and maintain strong relationships with wholesale power customers of both our utilities and non-regulated power generation businesses;

•	Selectively grow our non-regulated power generation business in targeted regional markets by developing assets and selling most of the capacity and energy production through mid- and long-term contracts primarily to load-serving utilities;

•	Exploit our fuel cost advantages and our operating and marketing expertise to produce and sell power at attractive margins;

•	Increase the value of our oil and gas properties by prudently growing our reserves and increasing our production of natural gas and crude oil;

•	Expand our energy marketing operations opportunistically in the area of natural gas, crude oil, coal, power and environmental products as market conditions warrant;

•	Diligently manage the credit, price and operational risks inherent in buying and selling energy commodities; and

•	Maintain an investment grade credit rating and ready access to debt and equity capital markets.

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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;

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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. In Colorado for instance, we filed an electric resource plan that includes enough renewable energy additions and GHG emission reductions to permit us to satisfy the State's requirement that 30% of a utility's distributed energy must be supplied by renewable energy resources by 2020. 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; 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 oil and natural gas operations as well as our fuel marketing and/or power generation activities. Specifically, we intend to focus our near term efforts on fully evaluating the 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 substantial portion of our established production for up to two years in the future; and

•	Enhance our oil and 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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•	New and interim rates were implemented in five utility jurisdictions increasing annual revenues $47.1 million:

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Construction of gas-fired generation to serve Colorado Electric customers is moving forward to start providing energy by January 1, 2012. The 180 MW generation project, including transmission, is expected to cost between $250 million and $260 million, of which $182.8 million has been expended through December 31, 2010. Construction commenced in July 2010 subsequent to the City of Pueblo annexing our site into the city and the receipt of the final air permit from the State of Colorado Department of Public Health and Environment;

•	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 will be retained so that full operations can be restored if needed;

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•	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, Nebraska, Nebraska Gas transferred assets serving approximately 3,000 customers to Metropolitan Utilities District on March 2, 2010. Nebraska Gas received $6.1 million in cash and recognized a $2.7 million gain on the sale of assets 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 proposes to construct a third 92 MW General Electric LMS100 natural gas-fired turbine at the site of our Pueblo Airport Generation Station currently under construction. Colorado Electric will file a Certificate of Public Convenience and Necessity in the first quarter of 2011 that will provide additional justification for the incremental 50 MW of generation capacity.

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Construction of gas-fired generation at Black Hills Colorado IPP to serve a 20-year PPA with Colorado Electric is moving forward to start providing energy by January 1, 2012. The 200 MW project is expected to cost between $250 million and $260 million, of which $162.6 million has been expended through December 31, 2010. Construction commenced in July 2010 subsequent to the City of Pueblo annexing our site into the city and the receipt of the final air permit from the State of Colorado Department of Public Health and Environment;

•	In May 2010, Enserco entered into a two-year $250 million committed stand-alone credit facility. The new facility includes a $100 million accordion feature which allows us, with the consent of the administrative agent, to increase commitments under the facility to $350 million;

•	In June 2010, Enserco expanded the commodities it markets through the acquisition of a coal marketing business for $2.25 million. Late in the third quarter of 2010, Enserco further expanded business lines to include power and environmental marketing. Our risk tolerances and capital allocated to the energy marketing segment are expected to remain the same;

•	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, which includes a $100 million accordion feature which allows us, with the consent of the administrative agent, to increase the capacity of the new facility to $600 million. The Revolving Credit Facility will be used to fund working capital needs and for other corporate purposes;

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•	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%;

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In November 2010, we entered into an equity forward offering for 4,000,000 shares. The offering will provide net proceeds of approximately $113.4 million. In December 2010, the underwriters exercised their option and purchased 413,519 additional shares netting an additional $11.7 million, bringing the total net proceeds to $125.1 million. We may settle the equity forward instruments at any time up to the maturity date of November 11, 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 137.5 basis points over LIBOR; and

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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 in regards to tax depreciation method changes.

•	New and interim rates were implemented in four utility jurisdictions increasing annual revenues by $16.5 million:

•	Construction of the Wygen III generation facility project continued in 2009. A 25% ownership interest in this generation facility was sold in April 2009. AFUDC increased $4.0 million related to this construction;

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•	Colorado Electric continued plans and purchases to construct 180 MW of utility-owned, gas-fired generation. AFUDC increased $1.2 million due to this construction activity;

•	Black Hills Power completed a first mortgage bond for $180.0 million. The bonds carry an interest rate of 6.125% and mature in November 2039. Interest from this debt and other debt transactions increased interest expense by $12.7 million;

•	We completed the repayment of $383.0 million of borrowings on our Acquisition Facility which was used to finance the Aquila Transaction on July 14, 2008; and

•	We completed our first full year of operations for Colorado Electric and the Gas Utilities acquired in the Aquila Transaction.

•	Oil and Gas recorded a $27.8 million non-cash after-tax ceiling test impairment loss in 2009 compared to a $59.0 million non-cash after-tax ceiling test impairment loss in 2008;

•	Power Generation's improved earnings reflect a gain of $26.0 million for the sale of a 23.5% ownership interest in the Wygen I power generation facility to MEAN;

•	Our Coal Mining segment executed a site lease agreement with the owners of the Wygen III plant increasing earnings $2.9 million for rental revenue in 2009;

•	Energy Marketing completed a one-year $300 million committed stand-alone credit facility in May 2009, to replace its previously uncommitted $300.0 million credit facility;

•	Black Hills Wyoming completed $120.0 million in project financing in December 2009. The loan matures in December 2016 with an interest rate of LIBOR plus 3.25% per annum; and

•	Black Hills Colorado IPP was selected to provide power to Colorado Electric and began planning and purchasing to build 200 MW of natural gas-fired electric generation to sell to Colorado Electric through a 20-year PPA.

•	We recorded an unrealized mark-to-market gain related to certain interest rate swaps of $55.7 million in 2009 compared to a $94.4 million loss recognized in 2008; and

•	We completed a $250.0 million public offering of senior notes due in 2014 in May 2009. The notes were priced at par and carry an interest rate of 9%.

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•	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 a $55.7 million unrealized mark-to-market gain in 2009; and

•	A $1.4 million increase in net interest expense primarily due to interest settlements of the de-designated interest rate swaps.

•	A $55.7 million unrealized mark-to-market gain in 2009 related to certain interest rate swaps that are no longer designated as hedges for accounting purposes compared to an unrealized mark-to-market loss of $94.4 million in 2008; and

•	2008 included $10.6 million in integration and acquisition costs related to the Aquila Transaction.

•	A $14.2 million increase in net interest expense primarily due to interest settlements of the de-designated interest rate swaps and amortization of amendment fees to extend the mandatory early termination dates of these swaps through the end of 2010.

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(1)

Capital expenditures for our Electric Utilities include expenditures associated with our Colorado Electric Energy Resource Plan. The construction of two natural gas-fired combustion turbine facilities at Colorado Electric is expected to cost approximately $250 million to $260 million; construction is expected to be completed by the end of 2011. The planned expenditures included in this table reflect the mid-point of this range. We expect to spend approximately $67 million to $77 million in 2011 for this construction.

(2)

Capital expenditures for our Power Generation segment include construction of two 100 MW natural gas-fired generation facilities at Black Hills Colorado IPP. The total construction cost is expected to be approximately $250 million to $260 million; construction is expected to be completed by the end of 2011. The planned expenditures included in this table reflect the mid-point of this range. We expect to spend approximately $87 million to $97 million in 2011 on this construction.

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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: $77.8 million in 2011, $77.6 million in 2012, $70.2 million in 2013, $51.3 million in 2014 and $39.7 million in 2015. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2010.

(c)

Unconditional purchase obligations include the capacity costs associated with our power purchase agreement with PacifiCorp, the capacity and energy costs associated with our power purchase agreement with PSCo, 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 2010 and price assumptions using existing prices at December 31, 2010. The pricing for the PSCo power purchase agreement is based on annual contracted capacity and an 85% load factor at current FERC approved rates. Our transmission obligations are based on filed tariffs as of December 31, 2010.

(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 to 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 2020.

(g)	Years 1-3 include an estimated reversal of approximately $7.9 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, 2010. These amounts have been excluded as it is impracticable to reasonably estimate the final amount and/or timing of any associated payments; and (2) contracts related to the construction of the 180 MW power generation facility by our Colorado Electric utility and 200 MW power generation facility by our Power Generation segment. We are in the process of procuring or have procured contracts for the turbines, building construction and labor. As of December 31, 2010, committed contracts for equipment purchases and for construction were 100% and 84% complete, respectively, for the Colorado Electric utility and 100% and 71% complete, respectively, for the Power Generation segment. Construction is expected to be completed at both facilities by December 31, 2011 with expenditures during 2011 of $67 million to $77 million for Colorado Electric and $87 million to $97 million for Black Hills Colorado IPP.

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•	Cash earnings (net income plus adjustments to reconcile income) were consistent with prior year. Net income results were negatively impacted by mark-to-market losses in 2010 on interest rate swaps but positively impacted by mark-to-market gains on interest rate swaps in 2009, offset by a ceiling test impairment in 2009, which do not impact cash flows from operations;

•	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 $97.8 million as a result of:

•	Outflows from changes in accounts receivable primarily from an increase in our Energy Marketing receivables;

•	Materials, supplies and fuel used funds of $26.3 million primarily from the purchases of gas and oil by our Energy Marketing segment;

•	Inflows from changes in accounts payable and other current liabilities primarily from our Energy Marketing segment; and

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

•	Higher cash earnings of $28.6 million (net income plus adjustments to reconcile income). Operating results were impacted by mark-to-market changes on interest rate swaps which do not impact cash flows from operations;

•	A $16.9 million contribution in 2009 to our defined benefit plans compared to $0.5 million in 2008;

•	Inflows from operating assets and liabilities of $124.4 million as a result of:

•	Inflows from changes in accounts receivable primarily from our Energy Marketing receivables;

•	Materials, supplies and fuel used funds of $13.4 million primarily relating to natural gas held in storage by our Energy Marketing segment;

•	Outflows from changes in accounts payable and other current liabilities primarily from Energy Marketing; and

•	A $39.0 million increase in cash flows from changes in regulatory assets primarily related to deferred gas

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

•	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; and

•	Foreign currency exchange risk associated with our natural gas marketing business transacted in Canadian dollars.

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(a)	Excludes unamortized premium or discount.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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•	Commodity price risk associated with our marketing businesses, 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 Gas Utilities segment resulting from commodity price changes;

•	Interest rate risk associated with variable rate credit facilities and project financing floating rate debt as described in Notes 8 and 9; and

•	Foreign currency exchange risk associated with natural gas marketing business transacted in Canadian dollars.

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(a)

When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.

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•	At December 31, 2010, we had $150.0 million of notional amount floating-to-fixed interest rate swaps designated as cash flow hedges in accordance with accounting guidance for derivatives and hedging and accordingly, the mark-to-market adjustments are recorded in Accumulated other comprehensive loss on the Consolidated Balance Sheets.

•

We also had $250.0 million notional amount interest rate swaps which were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. The swaps were originally designated as cash flow hedges in accordance with accounting standards for derivatives and the mark-to-market values were recorded in Accumulated other comprehensive loss on the Consolidated Balance Sheets. Based on credit market conditions that transpired during the fourth quarter of 2008, we determined it was probable that the forecasted long-term debt financings would not occur in the time period originally specified and as a result, the swaps were no longer effective hedges and the hedge relationships were de-designated.

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•

Through our BHEP subsidiary, we own a 44.7% non-operating interest in the Newcastle Gas Plant (the Gas Plant). The natural gas processing facility gathers and processes gas, primarily from the Finn-Shurley Field in Wyoming. We receive our proportionate share of the Gas Plant's net revenues and are committed to pay our proportionate share of additions, replacements and operating and maintenance expenses. As of December 31, 2010, our investment in the Gas Plant included $4.2 million in plant and equipment which is included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. This asset is included in the asset pool being depleted and therefore accumulated depreciation is not separated by asset. These items are included in the corresponding categories of operating revenues and expenses in the accompanying Consolidated Statements of Income.

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Our subsidiary, Black Hills Power, owns a 20% interest in the Wyodak Plant, a 362 MW coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining 80% and operates the Wyodak Plant. Black Hills Power receives 20% of the Plant's capacity and is committed to pay 20% of its additions, replacements and operating and maintenance expenses. Black Hills Power's share of direct expenses of the Wyodak Plant is included in the corresponding categories of Operating expenses in the accompanying Consolidated Statements of Income. 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 an agreement expiring in 2022. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC's coal reserves. Under the coal supply agreement, PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to adjustment for planned outages.

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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 65%. 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 35% of the additions, replacements and operating and maintenance expenses. For the year ended December 31, 2010, 2009 and 2008, Black Hills Power's share of direct expenses was $0.2 million, $0.1 million and $0.1 million, respectively.

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•	On April 1, 2010, the 110 MW Wygen III coal-fired generation facility began commercial operations. Black Hills Power owns 52% of this facility.

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In January 2009, Black Hills Wyoming sold a 23.5% undivided ownership interest in its 90 MW Wygen I Plant to MEAN and in conjunction with the sale, we entered into agreements with MEAN under which it 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 following the transaction. Black Hills Wyoming's share of direct expenses of the Wygen I Plant are included in Operating expenses in the accompanying Consolidated Statements of Income.

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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, 2010, the restricted net assets at our regulated Electric and regulated Gas Utilities were approximately $196.8 million.

•

Our Enserco credit facility is a borrowing base credit facility, the structure of which requires certain levels of tangible net worth and net working capital to be maintained for a given borrowing base election level. In order to maintain a borrowing base election level, Enserco may be restricted from making dividend payments to its parent company. Restricted net assets at Enserco totaled $93.0 million for this stand-alone Enserco Credit Facility at December 31, 2010.

•	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 $4.25 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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•	Electric Utilities, which supply regulated electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility services to Cheyenne, Wyoming and vicinity; and

•	Gas Utilities, which supply regulated gas utility service to Colorado, Iowa, Kansas and Nebraska. The regulated Gas Utilities were acquired in July 2008 as described in Note 23.

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•	Oil and Gas, which produces, explores and operates oil and natural gas interests located in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, Wyoming, Texas and California;

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Power Generation, which produces and sells power and capacity to wholesale customers. During 2010, the power plants were located in Wyoming and Idaho. In 2009 our Power Generation segment entered into a 20-year PPA to supply Colorado Electric with 200 MW of capacity and energy from power plants under construction in Colorado, which are expected to be placed in service by December 31, 2011. Additionally, in January 2011, we sold our ownership interests in the partnerships which own the Idaho facilities ;

•	Coal Mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; and

•	Energy Marketing, which provides natural gas, crude oil, coal, power, environmental marketing and related services primarily in the United States and Canada.

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•

The Black Hills Corporation Pension Plan covers eligible employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP. Effective January 1, 2010, this Plan (with the exception of bargaining unit participants) froze all new non-bargaining unit employees from participation in the Plan and froze the benefits of current non-bargaining participants except for the following group: those non-bargaining unit participants who are both 1) age 45 or older as of December 31, 2009 and have 10 years or more of credited service as of January 1, 2010; and 2) elect to continue to accrue additional benefits under the pension plan and consequently forego the additional age- and points-based employer contribution under the Company's 401(k) retirement savings plan. The assets and obligations for the Black Hills Corporation Plan were revalued July 31, 2009 in conjunction with the freeze of the plan and we recognized a pre-tax curtailment expense of approximately $0.3 million in the third quarter of 2009. In September 2010, the bargaining unit participants in the BHC Pension Plan voted to freeze all new bargaining unit employees from participation in the Plan and to freeze the benefits of current bargaining unit participants except for the following group: those bargaining unit participants who are both 1) age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently fore-go the additional age and points based employer contribution under the Company's 401(k) retirement savings plan. This change to the BHC Pension Plan is effective January 1, 2011. As a result of this freeze, Black Hills Power recognized a pre-tax curtailment expense of less than $0.1 million in the fourth quarter of 2010. BHC Plan benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service.

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The Cheyenne Light Pension Plan covers the bargaining unit employees of Cheyenne Light and benefits are based on years of service and compensation levels during the highest three consecutive 12-month periods of service, reduced by the vested benefits under the predecessor plans, if any. In 2009, the Cheyenne Light Plan was amended to freeze the benefits of non-bargaining unit employees. The valuation of the Cheyenne Light Pension Plan at December 31, 2009, resulted in recognition of a pre-tax curtailment expense of less than $0.1 million in the fourth quarter of 2009.

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The Black Hills Energy Pension Plan covers eligible employees of our utility subsidiaries doing business as Black Hills Energy. Benefits are based on years of service and compensation levels during the highest four consecutive years of the last ten years of service. In 2009, the Black Hills Energy Plan was amended to freeze the Plan to all new participants and froze the benefits of current participants except for the following group: 1) age 45 or older as of December 31, 2009 and have 10 years or more of credited service as of January 1, 2010; and 2) elect to continue to accrued additional benefits under the pension plan and consequently fore-go the additional age and points based employer contributions under the Company's 401(k) retirement savings plan.

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•	Black Hills Power's PPA with PacifiCorp, expiring in 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.

•	Colorado Electric's PPA with PSCo, expiring in 2011, for 300 MW in 2011. Pricing for the PPA is based on annual contracted capacity and an 85% load factor at current FERC approved rates.

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

•	Cheyenne Light's PPA with Duke Energy's Happy Jack wind site, expiring in September 2028, provides up to 29.4 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 in 2029, for 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.

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In conjunction with MDU's April 2009 purchase of 25% ownership interest in Wygen III, an agreement to supply 74 MW of capacity and energy through 2016 was modified. The sales to MDU have been integrated into Black Hills Power's control area and are considered part of our firm native load. MWs from the Wygen III unit are deemed to supply a portion of the required 74 MW. During periods of reduced production at Wygen III, 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;

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In March 2010, Black Hills Power entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette effective April 2010 that replaces a previous agreement. This PPA provided the City of Gillette, with an option to purchase a 23% ownership interest in Black Hills Power's Wygen III facility which commenced commercial operations on April 1, 2010. The City of Gillette exercised its option to purchase the 23% ownership interest in Wygen III and the transaction closed in July 2010. The PPA terminated upon the closing of the transaction. We retain responsibility for operations of the facility with a life-of-plant lease and agreement for operations and coal supply. Black Hills Power entered into an agreement with the City of Gillette to dispatch the City of Gillette's first 23% of net generating capacity. MWs from the Wygen III unit are deemed to supply a portion of the City of Gillette's capacity and energy annually. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23% 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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We have a purchase agreement with Basin Electric for the supply of 80 MW of capacity and energy through 2012 and a separate agreement to receive 80 MW of capacity and energy through 2012. The agreements were entered into with Basin Electric to accommodate delivery of electricity to Cheyenne Light's service territory. This contract is scheduled to terminate with the commercial operation date of Basin's Dry Fork Generation Station which is scheduled to occur on or about June 30, 2011;

•	Black Hills Power has a five-year PPA with MEAN, which commenced on April 1, 2010. 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

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In March 2009, our 10-year power sales contract between MEAN and Black Hills Power that originally would have expired in 2013 was re-negotiated and extended until 2023. MEAN will purchase 20 MW of unit-contingent capacity from the Neil Simpson II and Wygen III plants, with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II plants are as follows:

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•	The pricing used to determine reserves must be an average of the first-of-the-month prices over twelve-months instead of a one-day price at the end of the reporting period.

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The SEC established a new definition of "reliable technology" which broadens the technology that a company may use to establish reserves and categories. The new definition permits the use of any reliable technology to establish reserve volumes in addition to those established by production and flow test data. This new definition eliminates previous restrictions limiting allowable PUDs to be booked only one location away from a producing well. We elected to continue with our existing methodology for 2009 and 2010.

•	Companies are now permitted but not required to disclose probable and possible reserves. We have elected not to report on these additional reserve categories for 2009 and again in 2010.

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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 commencing prospectively from 2009. In 2010, we invested approximately $7.3 million to drill and develop 9 PUD locations from our 2009 inventory totaling approximately 3.6 Bcfe in proved developed reserve recognition. This represents approximately 2.3 Bcfe in PUD conversions with the difference being an upward revision from our 2009 PUD estimates for these same properties based on actual performance. Most of the reserves developed were in the Williston (1.9 Bcfe) and San Juan (1.6 Bcfe) Basins. We have 132 gross PUD locations as of December 31, 2010 located in five basins. These locations represent proved reserves of approximately 36.8 Bcfe, primarily in the Piceance Basin (21.8 Bcfe, 29 gross locations) and Williston Basin (10.9 Bcfe, 28 gross locations). Future development costs associated with these locations are approximately $72.4 million. None of our PUD locations have been reflected in our reserves for five or more years. Consistent with the new SEC guidance, these PUD locations will be monitored and reported each year until they are drilled or revised.

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

ITEM 9A.	CONTROLS AND PROCEDURES

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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

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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•	At December 31, 2010, we have $150.0 million of notional amount floating-to-fixed interest rate swaps designated as cash flow hedges in accordance with accounting guidance for derivatives and accordingly, the mark-to-market adjustments are recorded in Accumulated other comprehensive loss on the Condensed Balance Sheets of this Schedule I. The swaps have a maximum term of six years.

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We also have interest rate swaps with a notional amount of $250.0 million which were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. The swaps were originally designated as cash flow hedges in accordance with accounting guidance for derivatives and the mark-to-market values were recorded in Accumulated other comprehensive loss on the Condensed Balance Sheets of this Schedule I. Based on credit market conditions that transpired during the fourth quarter of 2008, we determined it was probable that the forecasted long-term debt financings would not occur in the time period originally specified and as a result, the swaps were no longer effective hedges and the hedge relationships were de-designated. Mark-to-market adjustments on the swaps are now recorded within the income statement and during 2010 we recorded a $15.2 million pre-tax unrealized mark-to-market loss to earnings, in 2009 we recorded a $55.7 million pre-tax unrealized mark-to-market gain to earnings and in 2008 we recorded a $94.4 million pre-tax unrealized mark-to-market loss to earnings. These swaps are eight and 18 year swaps which have amended mandatory early termination dates ranging from December 15, 2011 to December 29, 2011.

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3.	Exhibits

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