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•	Construction of Colorado Electric’s 180 megawatt power plant and Colorado IPP's 200 megawatt power plant in Pueblo, Colo., is on schedule and within budget. Commissioning of the two plants is ongoing with first fires achieved on all units and synchronization with the transmission grid complete for six of eight generators. The two plants will begin commercial operations Jan. 1, 2012.

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On April 28, 2011, Colorado Electric filed a rate request with the Colorado Public Utilities Commission seeking a $40.2 million, or an 18.8 percent, increase in annual revenue, with proposed new rates effective Jan. 1, 2012. Colorado Electric filed rebuttal testimony on Oct. 14 and a joint stipulation agreement on behalf of some intervenors and the utility was submitted to the Commission on Oct. 27. Commission hearings regarding the rate case began Nov. 1.

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On March 14, 2011, Colorado Electric filed a request for a certificate of public convenience and necessity with the Colorado Public Utilities Commission to construct a third utility-owned, 88 megawatt natural gas-fired turbine at the existing Pueblo generation location for an estimated $102 million. An initial settlement with intervenors was reached on Oct. 3 and a settlement hearing occurred on Oct. 25. Under the proposed settlement, Colorado Electric will own 42 megawatts of the 88 megawatt turbine and will sell the remaining 46 megawatts to a buyer who will provide the utility a seven-year capacity purchase agreement. The agreement also requires Colorado Electric to purchase the 46 megawatt ownership when the contract expires.

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The Colorado Public Utilities Commission issued a decision on Aug. 12, 2011 approving Colorado Electric's request to construct and rate base 50 percent ownership in a 29 megawatt wind turbine project located south of Pueblo, Colo. The decision included the authorization to conduct a competitive solicitation for ownership of the other 50 percent of the project. The project will require a net capital investment by the utility of $27 million and is expected to be operational no later than Dec. 31, 2012.

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On Nov. 1, 2011, Cheyenne Light filed a motion to rescind its filing for a certificate of public convenience and necessity with the Wyoming Public Service Commission to construct and operate a $158 million, 120 megawatt electric generation facility. This original filing was replaced with a new joint request filed on Nov. 1 by Cheyenne Light and Black Hills Power with the Wyoming Public Service Commission 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, Wyo. The proposed facility will include construction of one simple-cycle, 37 megawatt combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 megawatt unit that will be jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Light will own 40 megawatts and Black Hills Power will own 55 megawatts of the combined cycle unit.

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The Mancos horizontal test drilling program in the San Juan and Piceance Basins continued to advance. All three test wells have been drilled, cased and cemented. The San Juan Basin well has also been fracture stimulated and placed on production with initial flow rates of approximately 6.2 million cubic feet per day. The other two wells should be fracture stimulated and production tested by year-end.

•	On Nov. 1, 2011 the equity forward agreements with J. P. Morgan were settled by issuing 4,413,519 shares of Black Hills Corporation common stock in return for approximately $120 million in net cash proceeds. The proceeds were used to pay down the corporate revolver.

•	The $100 million, one-year, unsecured term loan originally executed Dec. 15, 2010, with a cost of borrowing of 137.5 basis points over LIBOR, was extended on the same terms for two years effective Sept. 30, 2011.

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(d)

Includes $24.9 million and $26.4 million net non-cash after-tax mark-to-market unrealized loss for the three and nine months ended Sept. 30, 2011 and $8.9 million and $27.1 million net non-cash after-tax mark-to-market unrealized loss for the three and nine months ended Sept 30, 2010, respectively. These unrealized losses are related to certain de-designated interest rate swaps. The three and nine months ended Sept. 30, 2011 also includes the elimination in consolidation of $0.5 million after-tax gain on sale of assets from a related party. Additionally, the three and nine months ended Sept. 30, 2011 includes a $2.0 million reduction of income taxes as a result of a re-measurement of a previously reported uncertain tax position due to a settlement with the IRS.

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•	Normal weather and operations within our utility service territories during the fourth quarter;

•	Slight earnings improvement in the Coal Mining business segment;

•	Oil and gas prices do not decrease significantly; and

•	Energy marketing earnings strengthen in fourth quarter with total 2011 net income exceeding 2010.

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•	Capital spending of $420 million to $440 million, including oil and gas capital expenditures of $95 million to $100 million;

•	Financings as necessary to maintain appropriate capital structure;

•	Exclusion of the impact of the mark-to-market changes for the $250 million of dedesignated interest rate swaps;

•	Normal operations and weather conditions within our utility service territories;

•	Successful completion of rate cases for the electric and gas utilities;

•	No significant unplanned outages at any of our power generation facilities;

•	Energy Marketing earnings more than double compared to 2011 forecasted earnings;

•	Continued improvement in Coal Mining with positive full year results;

•	Total oil and natural gas production in the range of 12.3 Bcfe to 13.0 Bcfe;

•	Oil and gas annual average NYMEX prices of $4.50 per MMBtu for natural gas and $87.65 per Bbl for oil; production-weighted average well-head prices of $3.41 per Mcf and $80.65 per Bbl of oil and average hedged prices received of $3.86 per Mcf and $79.01 per Bbl; and

•	No additional significant acquisitions or divestitures.

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(a)	Decrease in MWh sold during the nine months ended Sept. 30, 2011 reflects the termination of wholesale contracts when a previous wholesale power customer purchased an ownership interest in the Wygen III facility.

(b)	Includes 48,643 MWh and 222,091 MWh sold at Colorado Electric for the three and nine months ended Sept. 30, 2011, respectively. Pursuant to a rate case order with the Colorado PUC, the margins associated with these sales have been deferred until settlement of a sharing mechanism is finalized.

(c)	Availability for the nine months ended Sept. 30, 2011 was impacted by planned major overhauls and an extended outage at the PacifiCorp-operated Wyodak plant. Availability for the same period in 2010 was impacted by unplanned maintenance at the same plant.

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	(a) Represents activity from the coal marketing business acquired on June 1, 2010.

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•	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, transmission and purchased power in our regulated utilities and the timing in which the new rates would go into effect;

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

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

•	Our ability to generate significant earnings improvements in 2012 and beyond;

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

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

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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 or foreign exchange rates and the demand for our services, any of which can affect our earnings, financial liquidity and the underlying value of our assets, including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and oil reserves;

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

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

•	Forecasted capital expenditures associated with our oil and gas segment are driven, in part, by current market prices. Changes in crude and natural gas prices may cause us to change our planned capital expenditures related to our oil and gas operations;

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

•	Changes in or compliance with laws and regulations, particularly those related to financial reform legislation, taxation, power generation, safety, protection of the environment, energy marketing and hydraulic fracturing;

•	Weather and other natural phenomena;

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

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

•	Other factors discussed from time to time in our filings with the SEC.

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