Black Hills Corp. Reports 2012 Fourth Quarter and Full Year Results and Announces 43rd Consecutive Annual Dividend Increase

RAPID CITY, S.D.--()--Black Hills Corp. (NYSE: BKH) today announced 2012 fourth quarter and full-year financial results and the 43rd consecutive annual increase in the company’s dividend. Adjusted income from continuing operations, a non-GAAP measure,* for the fourth quarter of 2012 was $30.0 million, or $0.68 per share, compared to $19.7 million, or $0.46 per share, for the same period in 2011. For the 12 months ending Dec. 31, 2012, adjusted income from continuing operations was $92.2 million, or $2.09 per share, compared to $67.7 million, or $1.69 per share, for the same period in 2011.

The quarterly dividend was increased by $0.01 per common share to $0.38 per share, equivalent to an annual increase of $0.04 and dividend rate of $1.52 per share. Common shareholders of record at the close of business on Feb. 15, 2013, will receive $0.38 per share, payable on March 1, 2013.

“Considering the warm winter temperatures and low natural gas prices throughout 2012, we are very pleased with our earnings and operating results,” said David R. Emery, chairman, chief executive officer and president of Black Hills Corp. “Prudent management of our businesses, successful execution of our continuous improvement and cost-reduction initiatives, and increased earnings in most of our businesses largely offset the negative impacts of weather and gas prices.”

       
Three Months Ended Dec. 31, Twelve Months Ended Dec. 31,
(in millions, except per share amounts)     2012     2011     2012     2011
Non-GAAP:*        
Income from continuing operations, as adjusted $ 30.0 $ 19.7 $ 92.2 $ 67.7
Income (loss) from discontinued operations (0.2 )     6.8       (7.0 )     9.4
Net income, as adjusted (Non-GAAP) $ 29.8       $ 26.5       $ 85.2       $ 77.1
 
Earnings per share from continuing operations, as adjusted, diluted $ 0.68 $ 0.46 $ 2.09 $ 1.69
Earnings per share, discontinued operations       0.16       (0.16 )     0.23
Earnings per share, as adjusted (Non-GAAP) $ 0.68       $ 0.62       $ 1.93       $ 1.92
 
GAAP:
Income from continuing operations $ 30.9 $ 18.8 $ 88.5 $ 40.4
Income (loss) from discontinued operations (0.2 )     6.8       (7.0 )     9.4
Net income $ 30.8       $ 25.6       $ 81.5       $ 49.7
 
Earnings per share from continuing operations, diluted $ 0.70 $ 0.44 $ 2.01 $ 1.01
Income (loss) from discontinued operations       0.16       (0.16 )     0.23
Earnings per share, diluted $ 0.70       $ 0.60       $ 1.85       $ 1.24
 
* An accompanying schedule for the GAAP to Non-GAAP adjustment reconciliation is provided below.
 

“Despite the financial challenges in the first quarter, the company delivered adjusted earnings of $2.09 per share for 2012, up 24 percent compared to 2011, and toward the upper end of our revised guidance range,” Emery said. “The electric utilities and power generation businesses posted solid earnings growth driven by the significant investments in our new power plant complex in Pueblo, Colo. The coal mining business also improved, with a $6.0 million earnings increase year-over-year. The gas utilities performed very well against the backdrop of warm winter temperatures, with solid operational performance, including zero controllable outages during 2012.

“We are proud of our 130 years of service to our communities. We thank our customers and employees for their ongoing partnership. During 2012, we invested in our utility infrastructure and systems, improving the safe, reliable and affordable service our communities and utility customers depend on. We placed the Pueblo Airport Generating Station into service, completed the Busch Ranch wind project, built two major electric transmission lines in Colorado, and began development of the Cheyenne Prairie Generating Station. Our employee team accomplished all of this safely, reducing reportable accidents by 29 percent compared to 2011.

“We completed two major transactions in 2012 that reduced our company’s risk profile, improved our credit metrics and reduced our future equity financing needs. In February, we sold our energy marketing business, netting cash proceeds of $166 million. In September, our oil and gas business captured substantial value for shareholders by selling most of its Williston Basin oil and gas assets for $228 million. We used the proceeds to redeem $225 million of senior unsecured, 6.5 percent notes and will allow us to finance the Cheyenne Prairie Generating Station without the issuance of additional equity.

“In October, two credit rating agencies improved their ratings outlook for Black Hills Corp. from stable to positive. We believe the improved outlook recognizes the strength of our future earnings and cash flow, as well as the risk reduction and balance sheet benefits resulting from our two major sales transactions.

“On Jan. 31, 2013, we announced an increase in our quarterly dividend for the 43rd consecutive year, doubling the amount of increase from the previous year. Only two other electric or gas utility companies in the United States have a longer history of annual dividend increases. We take great pride in this record. It highlights the confidence we have in our business strategy, well-defined growth plans, ability to increase earnings and employee team.

“We are excited about our future. We have strong growth opportunities in our utilities and are encouraged by the potential of our Mancos Shale gas assets, based on our test well results and other operators’ recent announcements. By focusing on strong growth, a superior customer experience, and being a great workplace, we will continue our track record of creating shareholder value for years to come.”

Black Hills Corp. highlights for the fourth quarter and full year 2012, recent regulatory filings, updates and other events include:

Utilities

  • On Dec. 31, Colorado Electric suspended operations at its W.N. Clark coal-fired power plant in Cañon City, Colo. On Aug. 31, Black Hills Power suspended operations at its Ben French coal-fired power plant in Rapid City, S.D. These plants, along with several other previously identified plants, are planned for permanent retirement because of new state and federal environmental regulations. The affected plants are listed in the table below with their operations suspension date (if applicable) and their ultimate retirement date (if identified):
                       

Type of

Age of Plant

Plant

Company

Megawatts

Plant

Suspend Date

Retirement Date

(in years)

Osage Black Hills Power   34.5 Coal Oct. 1, 2010 March 21, 2014 64
Ben French Black Hills Power 25.0 Coal Aug. 31, 2012 March 21, 2014 52
Neil Simpson I Black Hills Power 21.8 Coal NA March 21, 2014 43
W.N. Clark Colorado Electric 42.0 Coal Dec. 31, 2012 Dec. 31, 2013 57
Pueblo Unit #5 Colorado Electric 9.0 Gas Dec. 31, 2012 to be determined 71
Pueblo Unit #6 Colorado Electric   20.0   Gas Dec. 31, 2012 to be determined 63
Total MW   152.3  
 
  • On Dec. 17, Black Hills Power filed a request with the South Dakota Public Utilities Commission seeking a 9.94 percent, or $13.7 million, increase in annual electric revenues.
  • On Dec. 17, Black Hills Power filed a request with the South Dakota Public Utilities Commission to use a construction financing rider for Cheyenne Prairie Generating Station in lieu of the traditional allowance for funds used during construction. This rider request, filed under recently amended state legislation, is a first in South Dakota. The rider will allow Black Hills Power to earn and collect a rate of return during the construction period on approximately a 40 percent share of the total project cost, while also lowering the overall cost of the project to customers. On Jan. 17, 2013, the commission approved a stipulation with interim rates effective April 1, 2013, subject to refund. The company anticipates a final commission ruling about the construction financing rider during the third quarter.
  • On Oct. 30, Cheyenne Light and Black Hills Power received approval from the Wyoming Public Service Commission to use a construction financing rider for Cheyenne Prairie Generating Station in lieu of the traditional allowance for funds used during construction. The rider allows Cheyenne Light and Black Hills Power to earn and collect a rate of return during the construction period on approximately a 60 percent share of the total project cost, while also lowering the overall cost of the project to customers.
  • On Oct. 16, Colorado Electric’s 29 megawatt Busch Ranch wind project commenced commercial operations. Colorado Electric’s share of the project’s cost was approximately $25 million. On Sept. 18, the company completed the sale of a 50 percent undivided ownership interest in the project. On Jan. 30, 2013, Colorado Electric received approval notification from the United States Treasury for an award letter grant in the amount of $8.4 million for our share of the Busch Ranch wind project.
  • On Sept. 27, Cheyenne Light and Black Hills Power received the final air permit for the Cheyenne Prairie Generating Station, finalizing all approvals and permits required for the new plant. The Wyoming Public Service Commission previously approved the certificate of public convenience and necessity authorizing the construction, operation and maintenance of the new 132 megawatt, $237 million natural gas-fired electric generating facility in Cheyenne, Wyo. The company has ordered all major equipment for the project and commencement of construction is expected this spring. Project costs for plant construction and associated transmission are estimated at $222 million, with up to $15 million of construction financing, for a total of $237 million.
  • On July 30, Colorado Electric filed its electric resource plan with the Colorado Public Utilities Commission. The company is seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant, consistent with a previous commission order that had mandated the plant be retired per the requirements of the Colorado Clean Air – Clean Jobs Act. The commission dismissed the initial filing without prejudice. It directed Colorado Electric to refile the resource plan and address alternatives for not just the replacement capacity for its coal-fired W.N. Clark power plant, but also for the retirement of the aging natural gas-fired steam turbines at Pueblo Units 5 and 6. On review, the commission confirmed Colorado Electric’s right to own the replacement capacity for the W.N. Clark power plant and extended the date to refile the resource plan to May 1, 2013.
  • On June 18, the Wyoming Public Service Commission approved settlement agreements increasing base rates for Cheyenne Light’s electric and natural gas customers effective July 1. The PSC approved increases of $2.7 million in annual electric revenue and $1.6 million in annual natural gas revenue. The settlements included a return on equity of 9.6 percent and a capital structure of 54 percent equity and 46 percent debt.
  • On June 4, Colorado Gas filed a request with the Colorado Public Utilities Commission for an increase in annual gas revenues to recover capital investments and increased operation and maintenance expenses. The filing was required by the commission as part of a 2008 rate case settlement. The commission approved a $0.2 million revenue increase with new rates effectives Dec. 10. The settlement included a return on equity of 9.6 percent and a capital structure of 50 percent equity and 50 percent debt.
  • On Jan. 1, Colorado Electric’s new 180 megawatt power plant near Pueblo, Colo. began commercial operations and started serving utility customers. New rates for Colorado Electric reflecting the new power plant investment were also implemented on Jan. 1. This plant was operational with availability greater than 95 percent during 2012.

Non-Regulated Energy

  • On Sept. 27, Oil and Gas sold approximately 85 percent of its Williston Basin assets for net cash proceeds of approximately $228 million.
  • In the third quarter, the company’s coal mining business commenced operations under its revised mine plan. Mining operations moved to an area with lower overburden ratios, which should reduce mining costs for the next several years.
  • In the second quarter, Oil and Gas recorded a $17.3 million after-tax, non-cash ceiling test impairment to the book value of its crude oil and natural gas properties, due to low natural gas prices.
  • On Jan. 1, Black Hills Colorado IPP’s new $261 million, 200 megawatt power plant near Pueblo, Colo., began commercial operations. Its output was sold to affiliate Colorado Electric under a 20-year power purchase agreement. This plant was operational with contract availability greater than 99 percent during 2012.

Corporate

  • On Oct. 31, the company redeemed $225 million of senior unsecured, 6.5 percent notes scheduled to mature on May 15, 2013.
  • In October, Standard & Poor’s Ratings Services and Moody’s Investors Service changed their credit ratings outlook for Black Hills Corp. from stable to positive.
  • On June 24, the company extended for one year its $150 million term loan at favorable terms.
  • On Feb. 1, the company entered into a new $500 million corporate revolving credit facility for five years at favorable terms.

Discontinued Operations

  • On Feb. 29, the company sold the outstanding stock of its energy marketing business, Enserco Energy Inc. Cash proceeds from the transaction were $166 million.
 
 
BLACK HILLS CORPORATION
CONSOLIDATED FINANCIAL RESULTS
 

(Minor differences may result due to rounding.)

 
(in millions)     Three Months Ended Dec. 31,     Twelve Months Ended Dec. 31,
2012     2011 2012     2011
Net income (loss):        
Utilities:
Electric (a) $ 14.1 $ 13.0 $ 51.6 $ 47.7
Gas 11.6       9.9   28.0       34.2  
Total Utilities Group 25.7       22.9   79.6       81.9  
 
Non-regulated Energy:
Power generation 5.4 0.9 21.3 3.0
Coal mining 1.7 0.7 5.6 (0.4 )
Oil and gas (b)       (1.2 ) (2.2 )     (1.7 )
Total Non-regulated Energy Group 7.1       0.4   24.7       0.9  
 
Corporate and Eliminations (a) (c) (d) (1.9 )     (4.7 ) (15.8 )     (42.4 )
 
Income from continuing operations 30.9       18.6   88.5       40.4  
 
Income (loss) from discontinued operations, net of tax (0.2 )     6.8   (7.0 )     9.4  
Net income $ 30.7       $ 25.5   $ 81.5       $ 49.8  
 
(a)   Financial results for the 12 months ended Dec. 31, 2011 include a $0.5 million after-tax gain on sale to a related party which is eliminated in consolidation.
(b) Oil and Gas financial results for the three and 12 months ended Dec. 31, 2012 include an after-tax gain on sale of the Williston Basin assets of $1.2 million and $18.9 million, respectively. Oil and Gas financial results for the 12 months ended Dec. 31, 2012 include a non-cash after-tax ceiling test impairment of $17.3 million.
(c) Financial results for the three and 12 months ended Dec. 31, 2012 include a non-cash after-tax gain related to mark-to-market adjustment on certain interest rate swaps of $3.1 million and $1.2 million respectively, and the three and 12 months ended Dec. 31, 2011 include a $0.9 million and a $27.3 million after-tax non-cash loss, respectively, for those same interest rate swaps.
(d) Financial results of our Energy Marketing segment have been classified 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 in the after-tax amounts of $0.7 million for the three months ended Dec. 31, 2011, and $0.6 million and $2.2 million for the 12 months ended Dec. 31, 2012 and 2011, respectively.
 
       
Three Months Ended Dec. 31, Twelve Months Ended Dec. 31,
2012     2011 2012     2011
Weighted average common shares outstanding (in thousands):        
Basic 43,903 42,119 43,820 39,864
Diluted 44,214 42,341 44,073 40,081
 
Earnings per share:
Basic -
Continuing Operations $ 0.70 $ 0.45 $ 2.02 $ 1.01
Discontinued Operations       0.16   (0.16 )     0.24
Total Basic Earnings Per Share $ 0.70       $ 0.61   $ 1.86       $ 1.25
 
Diluted -
Continuing Operations $ 0.70 $ 0.44 $ 2.01 $ 1.01
Discontinued Operations       0.16   (0.16 )     0.23
Total Diluted Earnings Per Share $ 0.70       $ 0.60   $ 1.85       $ 1.24
 

EARNINGS GUIDANCE

Black Hills reaffirms its guidance for 2013 earnings from continuing operations, as adjusted, to be in the range of $2.20 to $2.40 per share as most recently issued on Nov. 13, 2012.

CONFERENCE CALL AND WEBCAST

The company will host a live conference call and webcast at 11 a.m. EST on Friday, Feb. 1, 2013, to discuss the company’s financial and operating performance.

To access the live webcast and download a copy of the investor presentation, go to the Black Hills website at www.blackhillscorp.com and click on “Webcast” in the “Investor Relations” section. The presentation will be posted on the website before the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. Those interested in asking a question during the live broadcast or those without internet access can call 800-706-7749 if calling within the United States. International callers can call 617-614-3474. All callers need to enter the pass code 30113710 when prompted.

For those unable to listen to the live broadcast, a replay will be available on the company’s website or by telephone through Friday, Feb. 15, 2013, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 60073704.

USE OF NON-GAAP FINANCIAL MEASURE

As noted in this news release, in addition to presenting its earnings information in conformity with Generally Accepted Accounting Principles, the company has provided non-GAAP earnings data reflecting adjustments for special items as specified in the GAAP to Non-GAAP adjustment reconciliation table below. Income (loss) from continuing operations, as adjusted, and Net income (loss), as adjusted, is defined as Income (loss) from continuing operations and Net income (loss), adjusted for expenses and gains that the company believes do not reflect the company’s core operating performance. The company believes that non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. The company’s management uses these non-GAAP financial measures as an indicator for planning and forecasting future periods. These non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our presentation of these Non-GAAP financial measures should not be construed as an inference that our future results will be unaffected by other income and expenses that are unusual, non-routine or non-recurring.

GAAP TO NON-GAAP ADJUSTMENT RECONCILIATION

       
Three Months Ended Dec. 31, Twelve Months Ended Dec. 31,
(In millions, except per share amounts) 2012     2011 2012     2011
(after-tax)

 Income

    EPS Income     EPS Income     EPS Income     EPS
Income (loss) from continuing operations (GAAP) $ 30.9       $ 0.70   $ 18.8       $ 0.44   $ 88.5       $ 2.01   $ 40.4       $ 1.01
Adjustments, after-tax:                
Unrealized (gain) loss on certain interest rate swaps (3.1 ) (0.07 ) 0.9 0.02 (1.2 ) (0.03 ) 27.3 0.68
Asset impairment - ceiling test 17.3 0.39
Gain on sale of Williston Basin assets (1.2 ) (0.03 ) (18.9 ) (0.43 )
Incentive compensation - Williston Basin assets sale 0.4 0.01 2.6 0.06
Credit facility fee write off 1.0 0.02
Make-whole provision payment 3.0 0.07 3.0 0.07
Rounding                 (0.1 )            
Total adjustments (0.9 )     (0.02 ) 0.9       0.02   3.7       0.08   27.3       0.68
 
Income (loss) from continuing operations, as adjusted (Non-GAAP) 30.0 0.68 19.7 0.46 92.2 2.09 67.7 1.69
Income (loss) from discontinued operations, net of tax (0.2 )       6.8       0.16   (7.0 )     (0.16 ) 9.4       0.23
Net income (loss) (Non-GAAP) $ 29.8       $ 0.68   $ 26.5       $ 0.62   $ 85.2       $ 1.93   $ 77.1       $ 1.92
 

BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months and 12 months ended Dec. 31, 2012, compared to the three months and 12 months ended Dec. 31, 2011, are discussed below. The following business group and segment information does not include certain inter-company eliminations or discontinued operations. Minor differences in comparative amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated. Prior period information has been revised to reclassify information related to discontinued operations.

Utilities Group

Income from continuing operations for the Utilities Group for the three months ended Dec. 31, 2012, was $25.7 million, compared to $22.9 million for the same period in 2011 while income from continuing operations for the 12 months ended Dec. 31, 2012, was $79.6 million, compared to $81.9 million in 2011.

Electric Utilities

               
Three Months Ended Increase Twelve Months Ended Increase
Dec. 31, (Decrease) Dec. 31, (Decrease)
2012     2011     2012 vs. 2011 2012     2011     2012 vs. 2011
(in millions)
Gross margin $ 91.8       $ 79.4       $ 12.4   $ 353.5       $ 304.0       $ 49.5  
       
Operations and maintenance 36.4 36.7 (0.3 ) 146.5 142.8 3.7
Gain on sale of operating assets (0.8 ) 0.8
Depreciation and amortization 18.8       13.4       5.4   75.2       52.5       22.7  
Operating income 36.6 29.3 7.3 131.7 109.5 22.2
 
Interest expense, net (12.9 ) (9.2 ) (3.7 ) (51.0 ) (39.0 ) (12.0 )
Other (expense) income, net (0.1 ) (0.1 ) 1.2 0.5 0.7
Income tax benefit (expense) (9.5 )     (6.9 )     (2.6 ) (30.3 )     (23.3 )     (7.0 )
Income (loss) from continuing operations $ 14.1       $ 13.0       $ 1.1   $ 51.6       $ 47.7       $ 3.9  
 
       
Three Months Ended Dec. 31, Twelve Months Ended Dec. 31,
Operating Statistics:     2012     2011 2012     2011
Retail sales - MWh 1,122,604     1,133,960 4,598,080     4,590,800
Contracted wholesale sales - MWh 90,648 92,962 340,036 349,520
Off-system sales - MWh 481,751       534,620   1,652,949       1,788,005  
Total electric sales - MWh 1,695,003       1,761,542   6,591,065       6,728,325  
 
Total gas sales - Cheyenne Light - Dth 1,478,517       1,575,334   4,261,788       4,813,607  
 
Regulated power plant availability:                    
Coal-fired plants (a) 95.6 % 90.1 % 90.8 % 91.3 %
Other plants 97.2 % 98.5 % 96.9 % 96.4 %
Total availability     96.4 %     93.2 % 93.9 %     93.1 %

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

Fourth Quarter 2012 Compared to Fourth Quarter 2011

Gross margin increased primarily due to a $9.1 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric and Cheyenne Light, a $2.1 million construction savings incentive for Colorado Electric, a $0.8 million increase from the TCA, and a $0.8 million increase in wholesale and transmission margins as a result of increased prices. These are partially offset by a $0.9 million decrease for off-system sales margins impacted by recognizing $0.7 million of deferred margins upon settlement of Colorado Electric’s power marketing sharing mechanism with the Colorado Public Utilities Commission in 2011 and $0.9 million from the 2012 expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenance is consistent with the same period in the prior year primarily due to costs associated with operating the new 180 megawatt generating facility in Pueblo, Colo., and allocation of corporate costs driven by an increased asset base in the Electric Utility, offset by a decrease in off-system sales costs, which were higher in 2011 as a result of recognizing $1.2 million of deferred off-system sales marketing costs in the fourth quarter of 2011 upon settlement with the Colorado Public Utilities Commission.

Depreciation and amortization increased primarily due to a higher asset base associated with the new 180 megawatt generating facility constructed in Pueblo, Colo., and the capital lease assets associated with the 200 megawatt generating facility providing capacity and energy from Colorado IPP.

Interest expense, net increased primarily due to debt associated with the financing of the Pueblo generating facility for which interest was capitalized during construction in 2011.

Income tax: The effective tax rate increased in 2012 due to a lower adjustment for flow-through treatment related to a repairs deduction and a lower benefit from AFUDC - equity than in the same period in the prior year.

Full Year 2012 Compared to Full Year 2011

Gross margin increased primarily due to a $36 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, a $3.5 million increase from the TCA, a $4.4 million increase from wholesale and transmission margins from increased pricing, a $2.1 million construction savings incentive related to the new 180 megawatt generating facility in Pueblo, Colo., a $1.6 million increase from an Environmental Improvement Cost Recovery Adjustment rider at Black Hills Power,partially offset by a decrease of $1.5 million from the expiration of a reserve capacity agreement with PacifiCorp.

Operations and maintenance increased primarily due to the costs associated with operating the new 180 megawatt generating facility in Pueblo, Colo., including increased corporate allocations, partially offset by a $2.1 million reduction of major maintenance accruals related to the power plants announced for retirement and cost reduction initiatives.

Gain on sale of operating assets in 2011 relates to the sale of assets to a related party. The gain was eliminated in the consolidation.

Depreciation and amortization increased primarily due to a higher asset base associated with the new 180 megawatt generating facility in Pueblo, Colo., and the capital lease assets associated with the 200 megawatt generating facility providing capacity and energy from Colorado IPP.

Interest expense, net increased primarily due to debt associated with financing of the new 180 megawatt generating facility for which interest was capitalized during construction in 2011.

Income tax: The effective tax rate increased due to a lower income tax true up adjustment in 2012, while the prior year reflected an increased benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit.

Gas Utilities

               
Three Months Ended Increase Twelve Months Ended Increase
Dec. 31, (Decrease) Dec. 31, (Decrease)
2012     2011     2012 vs. 2011 2012     2011     2012 vs. 2011
(in millions)
Gross margin $ 59.0       $ 59.2       $ (0.2 ) $ 208.7       $ 222.6       $ (13.9 )
       
Operations and maintenance 29.3 30.8 (1.5 ) 117.4 122.0 (4.6 )
Depreciation and amortization 6.4       6.3       0.1   25.2       24.3       0.9  
Operating income 23.3 22.1 1.2 66.2 76.3 (10.1 )
 
Interest expense, net (6.3 ) (6.3 ) (24.0 ) (26.0 ) 2.0
Other (expense) income, net 0.1 0.2 (0.1 )
Income tax (expense) (5.4 )     (5.9 )     0.5   (14.3 )     (16.4 )     2.1  
Income (loss) from continuing operations $ 11.6       $ 9.9       $ 1.7   $ 28.0       $ 34.2       $ (6.2 )
 
    Three Months Ended Dec. 31,     Twelve Months Ended Dec. 31,
Operating Statistics:     2012     2011     2012     2011
Total gas sales - Dth 15,939,040     15,805,353 47,358,505     55,764,154
Total transport volumes - Dth 14,471,439 14,705,259 60,480,822 59,216,132
 

Fourth Quarter 2012 Compared to Fourth Quarter 2011

Gross margin was comparable to the same period in the prior year reflecting a $0.8 million increase from favorable weather in the fourth quarter of 2012 compared to the same period in the prior year and $0.8 million from improved non-regulated margins. Also, $2.0 million of costs in 2012 were recorded as a reduction of gross margin, while in 2011 these costs had been recorded in operations and maintenance.

Operations and maintenance decreased primarily due to reduced bad debt expense and cost reduction initiatives, partially offset by increased compensation and benefits. Also, $2.0 million of costs that in 2011 had been recorded in operations and maintenance were recorded as a reduction of gross margin in 2012.

Income tax: The effective tax rate for the fourth quarter of 2012 decreased compared to the same period in the prior year, primarily as a result of a favorable flow-through tax adjustment at Iowa Gas benefiting 2012.

Full Year 2012 Compared to Full Year 2011

Gross margin decreased primarily due to an $8.7 million impact from milder weather compared to the same period in the prior year. Heating degree days in 2012 were 14 percent lower than the prior year and 13 percent lower than normal. Also, $6.8 million of costs in 2012 were recorded as a reduction of gross margin, while these costs in 2011 had been recorded in operations and maintenance.

Operations and maintenance decreased primarily due to a reduction in bad debt expense, partially offset by increased compensation and benefits. Also, $6.8 million of costs that in 2011 had been recorded in operations and maintenance were recorded as a reduction of gross margin in 2012.

Interest expense, net decreased primarily due to lower interest rates and decrease in inter-company debt and associated expenses.

Income tax: The effective tax rate increased as a result of an unfavorable state tax true-up adjustment in 2012. Additionally, the 2011 period was favorably impacted as a result of federal research and development credits and a flow-through tax adjustment at Iowa Gas.

Non-Regulated Energy Group

Income from continuing operations from the Non-regulated Energy group for the three months ended Dec. 31, 2012, was $7.1 million, compared to a loss from continuing operations of $0.5 million for the same period in 2011. Income from continuing operations from the Non-regulated Energy group for the 12 months ended Dec. 31, 2012, was $24.7 million, compared to $0.9 million for the same period in 2011.

Power Generation

               
Three Months Ended Increase Twelve Months Ended Increase
Dec. 31, (Decrease) Dec. 31, (Decrease)
2012     2011     2012 vs. 2011 2012     2011     2012 vs. 2011
(in millions)
Revenue $ 20.1       $ 8.2       $ 11.9   $ 79.4       $ 31.7       $ 47.7  
       
Operations and maintenance 7.5 3.7 3.8 30.0 16.5 13.5
Depreciation and amortization 1.2       1.0       0.2   4.6       4.2       0.4  
Operating income 11.4 3.5 7.9 44.8 10.9 33.9
 
Interest expense, net (3.0 ) (1.9 ) (1.1 ) (14.8 ) (7.4 ) (7.4 )
Other income (expense), net (0.1 ) 0.1 1.1 (1.1 )
Income tax benefit (expense) (3.0 )     (0.5 )     (2.5 ) (8.7 )     (1.6 )     (7.1 )
Income (loss) from continuing operations $ 5.4       $ 0.9       $ 4.5   $ 21.3       $ 3.0       $ 18.3  
 
    Three Months Ended Dec. 31,     Twelve Months Ended Dec. 31,
Contracted Fleet Power Plant Availability     2012     2011 2012     2011
Gas-fired plants 99.6 %     97.0 % 99.4 %     98.4 %
Coal-fired plants 99.6 % 100.0 % 99.6 % 100.0 %
Total availability 99.6 % 98.1 % 99.4 % 99.0 %
 

Fourth Quarter 2012 Compared to Fourth Quarter 2011

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

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

Depreciation and amortization was comparable to 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 primarily due to interest expense associated with the financing of the Pueblo generating facility, which was capitalized during construction in 2011, partially offset by lower inter-company debt.

Income tax: The effective tax rate for the fourth quarter of 2012 increased compared to the same period in the prior year primarily due to a tax true-up adjustment.

Full Year 2012 Compared to Full Year 2011

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

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

Depreciation and amortization were 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 primarily due to interest expense associated with the financing of the Pueblo generating facility, which was capitalized during construction in 2011, partially offset by lower inter-company debt.

Other income (expense), net included a gain on sale of ownership interest in the partnership that held the Idaho generating facilities in 2011.

Income tax: The effective tax rate in 2012 was favorably impacted by a state tax true-up that included certain research and development tax credits.

Coal Mining

    Three Months Ended     Increase     Twelve Months Ended     Increase
Dec. 31, (Decrease) Dec. 31, (Decrease)
2012     2011     2012 vs. 2011 2012     2011     2012 vs. 2011
(in millions)
Revenue $ 15.0       $ 18.0       $ (3.0 ) $ 57.8       $ 66.9       $ (9.1 )
       
Operations and maintenance 10.4 14.9 (4.5 ) 42.6 56.6 (14.0 )
Depreciation, depletion and amortization 3.5       4.3       (0.8 ) 13.1       18.7       (5.6 )
Operating income (loss) 1.1 (1.2 ) 2.3 2.2 (8.4 ) 10.6
 
Interest (expense) income, net (0.2 ) 1.0 (1.2 ) 0.9 3.9 (3.0 )
Other income (expense) 0.5 0.5 2.6 2.2 0.4
Income tax benefit (expense) 0.3       0.3         (0.1 )     1.9       (2.0 )
Income (loss) from continuing operations $ 1.7       $ 0.7       $ 1.0   $ 5.6       $ (0.4 )     $ 6.0  
 
    Three Months Ended Dec. 31,     Twelve Months Ended Dec. 31,
2012     2011     2012     2011
Operating Statistics: (in thousands)
Tons of coal sold 1,055     1,538 4,246     5,692
 
Cubic yards of overburden moved 1,580 4,473 8,329 14,735
 

Fourth Quarter 2012 Compared to Fourth Quarter 2011

Revenue decreased primarily due to a 31 percent decrease in tons sold as a result of the expiration of an unprofitable train load-out contract at Dec. 31, 2011 and a utility plant suspension, partially offset by a 21 percent increase in average price per ton. The higher average sales price reflects the impact of price escalators and adjustments in certain of our sales contracts. In 2012, approximately 50 percent of our coal production was sold under contracts that include price adjustments based on actual mining costs.

Operations and maintenance decreased primarily from reduced overburden moved associated with lower sales volumes related to the expiration of an unprofitable train load-out contract at Dec. 31, 2011. Additionally, a revised mine plan resulted in fuel cost and headcount reductions.

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

Interest (expense) income, net reflected repayment of an inter-company note receivables and inter-company debt upon payment of a dividend to our parent.

Income tax: The effective tax rate decreased primarily due to tax benefits generated by percentage depletion.

Full Year 2012 Compared to Full Year 2011

Revenue decreased primarily due to a 25 percent decrease in tons sold as a result of the expiration of an unprofitable train load-out contract on Dec. 31, 2011, partially offset by increased tons sold to the Wyodak plant that experienced an outage in 2011. Approximately 50 percent of our current coal production is sold under contracts that include price adjustments based on actual mining cost increases.

Operations and maintenance decreased due to reduced overburden moved associated with lower sales volumes related to the expiration of an unprofitable train load-out contract on Dec. 31, 2011. Additionally, a revised mine plan resulted in fuel cost and headcount reductions.

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 the parent.

Income tax: The low effective tax rate in 2012 was primarily due to the impact of percentage completion and a tax return true-up,while 2011 was impacted by a favorable research and development credit.

Oil and Gas

               
Three Months Ended Increase Twelve Months Ended Increase
Dec. 31, (Decrease) Dec. 31, (Decrease)
2012     2011     2012 vs. 2011 2012     2011     2012 vs. 2011
(in millions)
Revenue $ 12.1       $ 23.9       $ (11.8 ) $ 79.1       $ 79.8       $ (0.7 )
       
Operations and maintenance 9.9 11.1 (1.2 ) 43.3 41.4 1.9
Gain on sale of operating assets (1.8 ) (1.8 ) (29.1 ) (29.1 )
Depreciation, depletion and amortization 3.7 13.1 (9.4 ) 38.5 35.7 2.8
Impairment of long-lived assets               26.9             26.9  
Operating income 0.3 (0.3 ) 0.6 (0.4 ) 2.7 (3.1 )
 
Interest expense, net (0.1 ) (1.7 ) 1.6 (3.9 ) (5.9 ) 2.0
Other (expense) income, net (0.2 ) 0.2 0.2 (0.2 ) 0.4
Income tax benefit (expense), net (0.2 )     0.9       (1.1 ) 1.9       1.7       0.2  
Income (loss) from continuing operations $       $ (1.2 )     $ 1.2   $ (2.2 )     $ (1.7 )     $ (0.5 )
 
    Three Months Ended Dec. 31,    

Percentage
Increase

    Twelve Months Ended Dec. 31,    

Percentage
Increase

Operating Statistics: 2012     2011     (Decrease)     2012     2011     (Decrease)
Bbls of crude oil sold 74,709     148,422 (50 )% 559,971     451,823 24 %
Mcf of natural gas sold 1,567,104 2,261,960 (31 )% 8,686,191 8,526,420 2 %
Gallons of NGL sold 734,105 827,803 (11 )% 3,485,514 3,674,814 (5 )%
Mcf equivalent sales 2,120,230 3,270,750 (35 )% 12,543,948 11,762,331 7 %
 
Depletion expense/Mcfe $ 1.44 $ 3.73 (61 )% $ 2.87 $ 2.76 4 %
 
    Dec. 31, 2012     Dec. 31, 2011
Oil and Gas Total Proved Crude Oil     Natural Gas     Total Crude Oil     Natural Gas     Total
Reserves: (a) (Mbbl)     (MMcf)     (MMcfe) (Mbbl)     (MMcf)     (MMcfe)
Total proved reserves 4,116 55,985 80,683 6,223 95,904 133,242
 
Average hedged price $ 83.27 $ 3.33 $ 79.74 $ 4.29
 
Well-head reserve prices $ 85.31 $ 2.24 $ 88.49 $ 3.59
 

(a) Oil and gas reserve information is based on reports prepared by Cawley, Gillespie & Associates, Inc. an independent consulting and engineering firm.

Fourth Quarter 2012 Compared to Fourth Quarter 2011

Revenue decreased primarily due to a 50 percent decrease in crude oil volumes sold, a 54 percent decrease in natural gas volumes sold partially due to a natural production decline at our Mancos formation test wells completed in late 2011 and early 2012, and a 7 percent decrease in the average hedged price received for natural gas sales, partially offset by an 8 percent increase in the average hedged price received for crude oil sales. Crude oil production decreases reflect the sale of our Williston Basin assets.

Operations and maintenance decreased primarily as a result of decreased production taxes related to lower revenue.

Gain on sale of operating assets represents a post-closing adjustment to the gain on 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, reduced the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.

Depreciation, depletion and amortization decreased primarily due to a lower depletion rate per Mcfe resulting from the sale of our Williston Basin assets.

Interest expense, net decreased due to lower inter-company debt.

Income tax benefit (expense): The effective tax rate in the fourth quarter of 2012 was impacted by an unfavorable property related deferred income tax true-up adjustment.

Full Year 2012 Compared to Full Year 2011

Revenue was comparable to prior year. Crude oil volumes sold increased 24 percent along with a 4 percent increase in the average price received for crude oil sales, partially offset by a 5 percent decrease in natural gas and NGL volumes sold and a 22 percent decrease in average price received for natural gas. Crude oil production increases reflect volumes from new wells in our drilling program in the Bakken shale formation prior to the sale of a majority of those assets on Sept. 27, 2012.

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

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 sale amount not recognized as gain reduced the full-cost pool and should significantly decrease the future depreciation, depletion and amortization rate.

Depreciation, depletion and amortization increased primarily due to the year-to-date impact from adjusting our expected 2012 reserves. This was caused by commodity price reserve revisions, as well as higher cost reserves associated with our remaining Bakken activities and a higher depletion rate per Mcfe on higher volumes prior to the sale of most of our Bakken shale formation assets.

Impairment of long-lived assets represents a write-down in the value of our natural gas and crude oil properties driven by low natural gas prices in the second quarter of 2012. The write-down reflected a 12-month average NYMEX price of $3.15 per Mcf, adjusted to $2.66 per Mcf at the wellhead, for natural gas, and $95.67 per barrel, adjusted to $85.36 per barrel at the wellhead, for crude oil.

Interest expense, net decreased primarily due to decreased debt as a result of the sale of the Williston Basin assets along with lower interest rates.

Income tax (expense) benefit: The effective tax rate for 2011 was positively impacted by a research and development credit and the benefit generated by percentage depletion had a lesser impact on the effective tax rate in 2012.

Corporate

Fourth Quarter 2012 Compared to Fourth Quarter 2011

Loss from continuing operations for the three months ended Dec. 31, 2012, was $1.8 million compared to loss from continuing operations of $4.6 million for the same period in the prior year. Results for the fourth quarter of 2012 reflect a $4.8 million non-cash unrealized mark-to-market gain related to certain interest rate swaps compared to the fourth quarter of 2011, which included a $1.4 million non-cash unrealized mark-to-market loss related to these same interest rate swaps. Corporate results for 2012 include a $7.1 million make-whole penalty for early repayment of debt, while 2011 includes $1.1 million of costs originally allocated to our Energy Marketing segment which could not be reclassified to discontinued operations in accordance with GAAP.

Full Year 2012 Compared to Full Year 2011

Loss from continuing operations for the 12 months ended Dec. 31, 2012, was $15.8 million compared to a loss from continuing operations of $42.4 million for the same period in the prior year. Results for the year ended Dec. 31, 2012 reflect a $1.9 million non-cash unrealized mark-to-market gain related to certain interest rate swaps compared to 2011, which included a $42.0 million non-cash unrealized mark-to-market loss related to these same interest rate swaps. Corporate results for 2012 include a $7.1 million make-whole penalty for early repayment of debt and $0.9 million in costs originally allocated to our Energy Marketing segment which could not be reclassified to discontinued operations in accordance with GAAP, while 2011 also includes $3.4 million of costs originally allocated to our Energy Marketing segment and could not be reclassified to discontinued operations in accordance with GAAP.

Discontinued Operations

On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds on the date of the sale were approximately $166.3 million, subject to final post-closing adjustments. The proceeds represent $108.8 million received from the buyer and $57.5 million cash retained from Enserco before closing.

Income (loss) from discontinued operations was $(7.0) million and $9.4 million for the twelve months ended Dec. 31, 2012 and Dec. 31, 2011, respectively. Results for 2012 include an after-tax loss on sale of $2.5 million.

Pursuant to the provisions of the Stock Purchase Agreement, the buyer originally requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment, reached a partial settlement and paid $1.4 million. If we do not reach a negotiated agreement with the buyer regarding the remaining amount, resolution will occur through the dispute resolution provision of the Stock Purchase Agreement.

ABOUT BLACK HILLS CORP.

Black Hills Corp. (NYSE: BKH) – a diversified energy company with a tradition of exemplary service and a vision to be the energy partner of choice – is based in Rapid City, S.D., with corporate offices in Denver and Papillion, Neb. The company serves 765,000 natural gas and electric utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company’s non-regulated businesses generate wholesale electricity, and produce natural gas, crude oil and coal. Black Hills employees partner to produce results that improve life with energy. More information is available at www.blackhillscorp.com.

CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This news release includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this news release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. This includes, without limitations, our 2013 earnings guidance. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 2011 Annual Report on Form 10-K filed with the SEC, and other reports that we file with the SEC from time to time, and the following:

  • The accuracy of our assumptions on which our earnings guidance is based;
  • Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings in periodic applications to recover costs for fuel, transmission and purchased power and the timing in which the new rates would go into effect;
  • Our ability to complete our capital program in a cost-effective and timely manner, including our ability to successfully develop our Mancos shale gas reserves located in the San Juan and Piceance Basins;
  • Our ability to provide accurate estimates of proved crude oil and gas reserves and future production and associated costs;
  • Our ability to successfully resolve the purchase price adjustments relating to the sale of Enserco Energy Inc.; and
  • Other factors discussed from time to time in our filings with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

   
Consolidating Income Statement
Three Months Ended Dec. 31, 2012

Electric
Utilities

   

Gas
Utilities

   

Power
Generation

   

Coal
Mining

   

Oil and
Gas

    Corporate    

Electric
Utility Inter-
Co Lease
Elim*

   

Power
Generation
Inter-Co
Lease Elim*

   

Other Inter-
Co
Eliminations

    Total
(in millions)
Revenue $ 158.8     $ 139.7     $ 1.0     $ 7.3     $ 12.1     $     $     $     $     $ 318.9
Inter-company revenue 4.3 19.1 7.7 52.5 0.4 (84.0 )
Fuel, purchased power and cost of gas sold   71.3         80.7                                         0.8                 (29.0 )       123.9  
Gross Margin   91.8         59.0         20.1         15.0         12.1         52.5         (0.8 )       0.4         (55.0 )       195.0  
 
Operations and maintenance 36.4 29.3 7.5 10.4 10.0 43.9 (49.1 ) 88.4
Gain on sale of operating asset (1.8 ) (1.8 )
Depreciation, depletion and amortization   18.8         6.4         1.2         3.5         3.7         2.9         (3.3 )       2.9         (2.9 )       33.2  
Operating income (loss)   36.6         23.3         11.4         1.1         0.3         5.7         2.4         (2.5 )       (3.1 )       75.3  
 
Interest expense, net (14.3 ) (6.6 ) (3.1 ) (0.2 ) (0.7 ) (28.7 ) 22.1 (31.5 )
Interest rate swaps - unrealized (loss) gain 4.8 4.8
Interest income 1.4 0.3 0.1 0.6 16.7 (18.6 ) 0.5
Other income (expense) 0.6 18.5 (18.8 ) 0.2
Income tax benefit (expense)   (9.5 )       (5.4 )       (3.0 )       0.3         (0.2 )       (0.5 )       (0.9 )       0.9                 (18.3 )
Income (loss) from continuing operations     $ 14.1       $ 11.6       $ 5.4       $ 1.7       $       $ 16.5       $ 1.5       $ (1.6 )     $ (18.3 )     $ 30.9  

* The new generating facility constructed by Black Hills Colorado IPP at our Pueblo Airport Generation site which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expenses of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidations.

   
Consolidating Income Statement
Three Months Ended Dec. 31, 2011

Electric
Utilities

   

Gas
Utilities

   

Power
Generation

   

Coal
Mining

    Oil and Gas     Corporate    

Inter-Co
Eliminations

    Total
(in millions)
Revenue $ 169.3     $ 151.7     $ 1.3     $ 9.7     $ 23.9     $     $     $ 356.0
Inter-company revenue 3.5 6.9 8.3 50.2 (68.8 )
Fuel, purchased power and cost of gas sold   93.4         92.6                                         (16.7 )       169.3  
Gross Margin   79.4         59.2         8.2         18.0         23.9         50.1         (52.1 )       186.7  
 
Operations and maintenance 36.7 30.9 3.7 14.9 11.1 45.2 (45.9 ) 96.4
Gain on sale of operating assets
Depreciation, depletion and amortization   13.4         6.3         1.0         4.3         13.1         3.0         (2.9 )       38.2  
Operating income (loss)   29.2         22.1         3.5         (1.1 )       (0.2 )       2.0         (3.3 )       52.1  
 
Interest expense, net (13.2 ) (7.6 ) (2.3 ) (1.7 ) (24.3 ) 26.8 (22.4 )
Interest rate swaps - unrealized (loss) gain (1.4 ) (1.4 )
Interest income 4.1 1.3 0.4 1.0 17.5 (23.7 ) 0.5
Other income (expense) (0.1 ) (0.1 ) 0.5 (0.2 ) 13.6 (13.6 ) 0.2
Income tax benefit (expense)   (6.9 )       (5.9 )       (0.5 )       0.3         0.9         1.8                 (10.3 )
Income (loss) from continuing operations $ 13.0       $ 9.9       $ 0.9       $ 0.7       $ (1.2 )     $ 9.2       $ (13.8 )     $ 18.8  
 
   
Consolidating Income Statement
Twelve Months Ended Dec. 31, 2012

Electric
Utilities

   

Gas
Utilities

   

Power
Generation

   

Coal
Mining

   

Oil and
Gas

    Corporate    

Electric
Utility
Inter-Co
Lease
Elim*

   

Power
Generation
Inter-Co
Lease Elim*

   

Other Inter-
Co
Eliminations

    Total
(in millions)
Revenue $ 610.7     $ 454.1     $ 4.2     $ 25.8     $ 79.1     $     $     $     $     $ 1,173.9
Inter-company revenue 16.2 75.2 32.0 196.5 1.6 (321.5 )
Fuel, purchased power and cost of gas sold   273.5         245.3                                         3.2                 (115.0 )       407.1  
Gross Margin   353.5         208.7         79.4         57.8         79.1         196.5         (3.2 )       1.6         (206.5 )       766.8  
 
Operations and maintenance 146.5 117.4 30.0 42.6 43.3 179.1 (188.1 ) 370.7
Gain on sale of operating asset (29.1 ) (29.1 )
Depreciation, depletion and amortization 75.2 25.2 4.6 13.1 38.5 10.9 (13.0 ) 11.1 (10.9 ) 154.6
Impairment of long-lived assets                                   26.9                                         26.9  
Operating income (loss)   131.7         66.2         44.8         2.2         (0.4 )       6.5         9.8         (9.4 )       (7.6 )       243.7  
 
Interest expense, net (59.2 ) (26.7 ) (15.5 ) (0.2 ) (4.5 ) (92.7 ) 85.2 (113.6 )
Interest rate swaps - unrealized (loss) gain 1.9 1.9
Interest income 8.2 2.8 0.7 1.2 0.6 64.7 (76.1 ) 2.0
Other income (expense) 1.2 0.1 2.6 0.2 48.8 (49.9 ) 3.0
Income tax benefit (expense)   (30.3 )       (14.3 )       (8.7 )       (0.1 )       1.9         3.2         (3.6 )       3.4                 (48.4 )
Income (loss) from continuing operations     $ 51.6       $ 28.0       $ 21.3       $ 5.6       $ (2.2 )     $ 32.3       $ 6.3       $ (6.0 )     $ (48.4 )     $ 88.5  

* The new generating facility constructed by Black Hills Colorado IPP at our Pueblo Airport Generation site which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expenses of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidations.

   
Consolidating Income Statement
Twelve Months Ended Dec. 31, 2011

Electric
Utilities

   

Gas
Utilities

   

Power
Generation

   

Coal
Mining

   

Oil and Gas

    Corporate    


Eliminations

    Total
(in millions)
Revenue $ 600.9     $ 554.6     $ 4.1     $ 32.8     $ 79.8     $     $     $ 1,272.2
Inter-company revenue 13.4 27.6 34.1 192.3 (267.3 )
Fuel, purchased power and cost of gas sold   310.4         332.0                                 0.1         (67.4 )       575.0  
Gross Margin   304.0         222.6         31.7         66.9         79.8         192.2         (199.9 )       697.2  
 
Operations and maintenance 142.8 122.0 16.5 56.6 41.4 170.9 (174.9 ) 375.4
Gain on sale of operating assets (0.8 ) 0.8
Depreciation, depletion and amortization   52.5         24.3         4.2         18.7         35.7         11.2         (11.0 )       135.6  
Operating income (loss)   109.5         76.3         10.9         (8.4 )       2.7         10.0         (14.8 )       186.2  
 
Interest expense, net (53.8 ) (31.6 ) (8.9 ) (5.9 ) (93.3 ) 102.1 (91.4 )
Interest rate swaps - unrealized (loss) gain (42.0 ) (42.0 )
Interest income 14.8 5.6 1.5 3.9 64.3 (88.1 ) 2.0
Other income (expense) 0.5 0.2 1.1 2.2 (0.2 ) 46.5 (46.6 ) 3.7
Income tax benefit (expense)   (23.3 )       (16.4 )       (1.6 )       1.9         1.7         19.3         0.3         (18.2 )
Income (loss) from continuing operations $ 47.7       $ 34.2       $ 3.0       $ (0.4 )     $ (1.7 )     $ 4.8       $ (47.1 )     $ 40.4  
 

Contacts

Black Hills Corp.
Jerome Nichols, 605-721-1171
or
Media Relations Line, 866-243-9002

Release Summary

Q4 earnings release, Black Hills Corporation releases

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Contacts

Black Hills Corp.
Jerome Nichols, 605-721-1171
or
Media Relations Line, 866-243-9002