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Black Hills Corp. Reports 20 Percent Increase In 2012 Third Quarter Adjusted Earnings Per Share, Reaffirms 2012 Earnings Guidance And Initiates 2013 Earnings Guidance

Power Generation

  Three Months Ended     Nine Months Ended  
Sept. 30, Variance Sept. 30, Variance
2012   2011   2012 vs. 2011   2012   2011   2012 vs. 2011
(in millions)
Revenue $ 21.0     $ 8.1     $ 12.9   $ 59.3     $ 23.5     $ 35.8  
   
Operations and maintenance 7.8 4.6 3.2 22.5 12.9 9.6
Depreciation and amortization 1.2     1.1     0.1   3.4     3.2     0.2  
Operating income 12.0 2.4 9.6 33.4 7.5 25.9
 
Interest expense, net (3.1 ) (1.8 ) (1.3 ) (11.8 ) (5.5 ) (6.3 )
Other (income) expense, net 1.2 (1.2 )
Income tax benefit (expense) (3.8 )   (0.3 )   (3.5 ) (5.7 )   (1.1 )   (4.6 )
Income (loss) from continuing operations $ 5.1     $ 0.3     $ 4.8   $ 16.0     $ 2.1     $ 13.9  
 
  Three Months Ended Sept. 30,   Nine Months Ended Sept. 30,
2012   2011   2012   2011
Operating Statistics:    
Contracted fleet power plant availability -
Coal-fired plants 99.4 % 97.1 % 99.5 % 98.9 %
Gas-fired plants 99.4 % 100.0 % 99.3 % 100.0 %
Total availability 99.4 % 98.1 % 99.4 % 99.3 %
 

Third Quarter 2012 Compared with Third Quarter 2011

Revenue increased due to the commencement of commercial operation of our new 200 megawatt generating facility in Pueblo, Colo. on Jan. 1, 2012.

Operations and maintenance increased primarily due to the costs to operate and corporate allocations relating to our new 200 megawatt generating facility in Pueblo, Colo., which began serving customers on Jan. 1, 2012.

Depreciation and amortization was comparable to the same period in the prior year. The new generating facility's PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net increased due to interest costs for financing the Pueblo generating facility. Interest costs were capitalized during construction in the prior year.

Coal Mining
  Three Months Ended     Nine Months Ended  
Sept. 30, Variance Sept. 30, Variance
2012   2011   2012 vs. 2011   2012   2011   2012 vs. 2011
(in millions)
Revenue $ 14.7     $ 17.8     $ (3.1 ) $ 42.8     $ 48.9     $ (6.1 )
   
Operations and maintenance 10.8 14.2 (3.4 ) 32.1 41.8 (9.7 )
Depreciation, depletion and amortization 2.9     5.2     (2.3 ) 9.6     14.4     (4.8 )
Operating income (loss) 1.0 (1.5 ) 2.5 1.1 (7.2 ) 8.3
 
Interest income, net 1.0 (1.0 ) 1.2 2.9 (1.7 )
Other income (expense) 0.5 0.5 2.1 1.7 0.4
Income tax benefit (expense) 0.2     0.5     (0.3 ) (0.4 )   1.6     (2.0 )
Income (loss) from continuing operations $ 1.7     $ 0.6     $ 1.1   $ 3.9     $ (1.1 )   $ 5.0  
 
  Three Months Ended Sept. 30,   Nine Months Ended Sept. 30,
2012   2011   2012   2011
Operating Statistics: (in thousands)
Tons of coal sold 1,105   1,550 3,191   4,155
 
Cubic yards of overburden moved 1,827 3,873 6,749 10,261
 

Third Quarter 2012 Compared with Third Quarter 2011

Revenue decreased primarily due to a 29 percent decrease in tons sold as a result of the December 2011 expiration of an unprofitable train load-out contract which represented approximately 29 percent of our tons sold in 2011, partially offset by an increase in average sales price as a result of price escalators and adjustments in certain of our sales contracts. Approximately 50 percent of our current coal production is sold under contracts that include price adjustments based on actual mining costs.

Operations and maintenance decreased primarily from reduced overburden moved related to lower sales volumes and mining efficiencies, including decreased fuel costs and headcount reductions as a result of the revised mine plan and termination of the train load-out contract at Dec. 31, 2011.

Depreciation, depletion and amortization decreased primarily due to lower equipment usage and lower depreciation of mine reclamation asset retirement costs.

Interest income, net decreased primarily due to a decrease in inter-company notes receivable upon payment of a dividend to our parent.

Income tax benefit (expense) benefited from a change in the effective tax rate which was primarily due to the impact of percentage depletion and a tax return true-up.

Oil and Gas
  Three Months Ended     Nine Months Ended  
Sept. 30, Variance Sept. 30, Variance
2012   2011   2012 vs. 2011   2012   2011   2012 vs. 2011
(in millions)
Revenue $ 24.7     $ 19.2     $ 5.5   $ 67.0     $ 55.9     $ 11.1  
   
Operations and maintenance 12.1 9.6 2.5 33.3 30.3 3.0
Depreciation, depletion and amortization 12.5 7.7 4.8 34.8 22.6 12.2
Gain on sale of operating assets (27.3 ) (27.3 ) (27.3 ) (27.3 )
Impairment of long-lived assets           26.9         26.9  
Operating income 27.4 1.9 25.5 (0.7 ) 2.9 (3.6 )
 
Interest expense, net (1.1 ) (1.5 ) 0.4 (3.9 ) (4.2 ) 0.3
Other (income) expense 0.1 0.1 0.2 0.2
Income tax benefit (expense), net (9.0 )   (0.2 )   (8.8 ) 2.2     0.8     1.4  
Income (loss) from continuing operations $ 17.4     $ 0.2     $ 17.2   $ (2.2 )   $ (0.6 )   $ (1.6 )
 
    Percentage     Percentage
Three Months Ended Sept. 30, Increase Nine Months Ended Sept. 30, Increase
Operating Statistics: 2012   2011   (Decrease)   2012   2011   (Decrease)
Bbls of crude oil sold 184,423   98,950 86 % 485,262   303,401 60 %
Mcf of natural gas sold 2,278,801 2,147,172 6 % 7,119,087 6,264,460 14 %
Gallons of NGL sold 1,099,198 993,752 11 % 2,751,409 2,847,011 (3 )%
Mcf equivalent sales 3,542,367 2,882,837 23 % 10,423,717 8,491,582 23 %
 
Depletion expense/Mcfe $ 3.26 $ 2.38 37 % $ 3.07 $ 2.38 29 %
 
  Three Months Ended Sept. 30, 2012   Three Months Ended Sept. 30, 2011
    Natural Gas       Natural Gas
Average Prices Crude Oil Natural Gas Liquids Crude Oil Natural Gas Liquids
(Bbl)   (MMcf)   (gallons)   (Bbl)   (MMcf)   (gallons)
Average hedged price received $ 88.69 $ 3.07 $ 0.65 $ 82.76 $ 4.24 $ 0.88
 
Average well-head price $ 88.83 $ 1.87 $ 85.07 $ 3.00
 
Nine Months Ended Sept. 30, 2012   Nine Months Ended Sept. 30, 2011
Natural Gas Natural Gas
Average Prices Crude Oil Natural Gas Liquids Crude Oil Natural Gas Liquids
(Bbl)   (MMcf)   (gallons)   (Bbl)   (MMcf)   (gallons)
Average hedged price received $ 81.65 $ 3.27 $ 0.77 $ 76.25 $ 4.39 $ 0.94
 
Average well-head price $ 84.33 $ 1.61 $ 88.12 $ 2.87
 

Third Quarter 2012 Compared with Third Quarter 2011

Revenue increased primarily due to an 86 percent increase in crude oil sales, due primarily to activities from new wells in our drilling program in the Bakken shale formation and a 7 percent increase in the average price received for crude oil sold. A 6 percent increase in natural gas and NGL volumes, due primarily to the production from three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a 28 percent decrease in the average price received for natural gas.

Operations and maintenance costs increased primarily due to higher costs from non-operated wells and higher compensation and benefit costs.

Depreciation, depletion and amortization increased primarily due to the year-to-date impact from adjusting expected 2012 reserve additions due to the deferred drilling activities in the San Juan Mancos formation, as well as higher cost reserves associated with our Bakken activities and a higher depletion rate per Mcfe on higher volumes.

Gain on sale of operating assets represents the gain on the sale of our Williston Basin assets. We follow the full-cost method of accounting for oil and gas activities, which typically does not allow for gain on sale recognition unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The remainder of the sales amount, not recognized as gain, reduces the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.

Income tax (expense) benefit: For 2012, the benefit generated by percentage depletion had a significantly reduced impact on the effective tax rate compared to the same period in 2011.

Corporate

Third Quarter 2012 Compared with Third Quarter 2011

Loss from continuing operations for Corporate was $4.2 million for the three months ended Sept. 30, 2012 compared to loss from continuing operations of $28.6 million for the three months ended Sept. 30, 2011. The variance from the prior year was primarily as a result of an incentive compensation accrual recorded as a result of the Williston Basin asset sale and an unrealized, non-cash mark-to-market gain on certain interest rate swaps for the quarter ended Sept. 30, 2012 of approximately $0.6 million compared to a loss of $38.2 million unrealized, non-cash mark-to-market loss on these interest rate swaps in the prior year.

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