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

Black Hills Corp. (NYSE: BKH) today announced 2012 third quarter financial results. Income from continuing operations, as adjusted, was $18.7 million, or $0.42 per diluted share, compared with $13.7 million, or $0.35 per diluted share, for the same period in 2011 (this is a non-GAAP measure and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided).

“Our businesses performed very well in the third quarter, with adjusted earnings per share up 20 percent,” said David R. Emery, chairman, president and chief executive officer of Black Hills Corp. “We had continued strong earnings contributions from our electric utilities, and I am particularly pleased with the ongoing earnings improvements in our power generation and coal mining segments. Our oil and gas segment reported strong production gains that were offset by lower average natural gas prices and higher depletion expenses.

“During the quarter, we closed on the sale of our Williston Basin oil and gas assets for net cash proceeds of $227 million. We reported a $17.7 million after-tax gain from the sale in the quarter. We believe that the sales price and the overall transaction provided an exceptional value for our shareholders.

“Given our continued strong performance, we expect 2012 earnings from continuing operations, as adjusted, to be toward the upper half of our $1.90 to $2.10 per share range. We also expect strong earnings growth in 2013 and are issuing guidance of $2.20 to $2.40 per share from continuing operations, as adjusted.”
  Three Months Ended Sept. 30,   Nine Months Ended Sept. 30,
(in millions, except per share amounts)   2012   2011   2012   2011
Non-GAAP *:    
Income from continuing operations, as adjusted $ 18.7 $ 13.7 $ 62.3 $ 48.0
Income (loss) from discontinued operations, net of tax (0.2 )   0.6     (6.8 )   2.5
Net income, as adjusted (non-GAAP) $ 18.5     $ 14.3     $ 55.5     $ 50.5
 
Earnings per share from continuing operations, as adjusted, diluted $ 0.42 $ 0.35 $ 1.41 $ 1.21
Earnings (loss) per share, discontinued operations, net of tax     0.02     (0.16 )   0.07
Earnings per share, as adjusted, diluted (non-GAAP) $ 0.42     $ 0.37     $ 1.25     $ 1.28
 
GAAP:
Income from continuing operations $ 34.6 $ (11.2 ) $ 57.6 $ 21.6
Income (loss) from discontinued operations, net of tax (0.2 )   0.6     (6.8 )   2.5
Net income $ 34.5     $ (10.5 )   $ 50.8     $ 24.1
 
Earnings per share from continuing operations, diluted $ 0.78 $ (0.29 ) $ 1.31 $ 0.54
Income (loss) from discontinued operations, net of tax     0.02     (0.16 )   0.07
Earnings per share, diluted   $ 0.78     $ (0.27 )   $ 1.15     $ 0.61
 

* This is a Non-GAAP measure, and an accompanying schedule for the GAAP to Non-GAAP adjustment reconciliation is provided below.

“Two key strategic utility projects advanced during the quarter,” Emery said. “Cheyenne Light and Black Hills Power received final approvals and permits to build the 132 megawatt, $237 million natural gas-fired Cheyenne Prairie Generating Station in Cheyenne, Wyo., and Colorado Electric’s Busch Ranch wind project south of Pueblo, Colo. was placed into service on Oct. 16.

“In October, two of the three credit rating agencies changed their ratings outlook for Black Hills Corp. and Black Hills Power from stable to positive. We believe the outlook change recognizes our lower business risk profile and debt reduction efforts.

“We executed well in the third quarter with solid operating performance and improved earnings. Our cost-containment efforts to mitigate the earnings challenges of the first quarter are yielding positive results, and those efforts will continue throughout the remainder of 2012.”

Black Hills Corp. highlights for third quarter 2012, recent regulatory filings and updates, and other events include:

Utilities
  • Cheyenne Light and Black Hills Power received final approvals and permits for the Cheyenne Prairie Generating Station. The Wyoming Public Service Commission approved the certificate of public convenience and necessity on July 31 authorizing the construction, operation and maintenance of a new 132 megawatt, $237 million natural gas-fired electric generating facility in Cheyenne, Wyo. The state of Wyoming issued the air permit for the project on Aug. 31, and the U.S. Environmental Protection Agency issued the greenhouse gas air permit on Sept. 27. Upon receipt of this final permit, the major equipment for the project was ordered. Commencement of construction is expected in spring 2013. Project costs for plant construction and associated transmission are estimated at $222 million, with up to $15 million of construction financing costs, for a total of $237 million.
  • 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 the approximately 60 percent of the project cost related to serving Wyoming customers. The company is evaluating filing for a similar rider in South Dakota.
  • On Oct. 16, Colorado Electric’s 29 megawatt Busch Ranch wind project south of Pueblo, Colo., commenced commercial operation. Colorado Electric’s share of the project’s cost is approximately $26 million. On Sept. 18, the company completed the sale of a 50 percent undivided ownership interest in the project to the co-owner.
  • On Aug. 6, Black Hills Power and Colorado Electric announced plans to suspend plant operations at some of their older coal-fired and natural gas-fired facilities. In addition, the companies identified retirement dates for the older coal-fired power plants because of 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 40.0 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
 
  • On July 30, Colorado Electric filed its electric resource plan with the Colorado Public Utilities Commission seeking to develop and own replacement capacity for the retirement of the coal-fired W.N. Clark power plant, which was previously ordered to be retired by the commission to comply with the Colorado Clean Air – Clean Jobs Act. The commission dismissed the initial filing and directed Colorado Electric to refile the ERP by Jan. 18, 2013 in order to address alternatives for the replacement capacity for its coal-fired W.N. Clark power plant, as well as the retirement of Pueblo No. 5 and No. 6. The commission also directed Colorado Electric to request certificates of public convenience and necessity for any replacement capacity that Colorado Electric seeks to develop and own.
  • 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 commission required this rate case filing as part of a previous settlement agreement when Black Hills Corp. purchased Colorado Gas. All parties reached a rate case settlement, and the settlement hearing was held on Oct. 12, 2012. A decision is expected in the first quarter of 2013. The settlement, if approved, includes a $0.2 million revenue increase, a return on equity of 9.6 percent, a cost of debt of 7.2 percent, and a capital structure of 50 percent equity and 50 percent debt.
  • Weather was a contributing factor for utility results in the third quarter. Our service territories reported warmer weather, as measured by degree days, compared with the 30-year average and the same period last year. Although temperatures were above normal, weather-related demand was tempered by significantly lower humidity in the company’s service territories in 2012 compared with 2011.

Non-regulated Energy
  • On Sept. 27, the company’s oil and gas business segment sold approximately 85 percent of its Williston Basin assets for net cash proceeds of approximately $227 million.

Corporate
  • On Oct. 31, the company redeemed $225 million of senior unsecured, 6.5 percent notes which were originally scheduled to mature on May 15, 2013.
  • On Oct. 30, Black Hills Corp. declared a quarterly dividend of $0.37 per share, equivalent to an annual dividend rate of $1.48 per share. Through 2012, the company has increased its dividend for 42 consecutive years.
  • On Oct. 16, Standard & Poor’s Ratings Services changed its credit ratings outlook for Black Hills Corp. and Black Hills Power from stable to positive. On Oct. 18, Moody’s Investors Service also changed its credit ratings outlook for Black Hills Corp. and Black Hills Power from stable to positive.

BLACK HILLS CORPORATION

CONSOLIDATED FINANCIAL RESULTS
   

(Minor differences may result due to rounding.

Prior period information has been revised to reclassify information related to discontinued operations.)
 
(in millions) Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2012   2011 2012   2011
Net income (loss):    
Utilities:
Electric $ 14.6 $ 15.8 $ 37.5 $ 34.6
Gas     0.6   16.4     24.3  
Total Utilities Group 14.6     16.4   53.9     58.9  
 
Non-regulated Energy:
Power generation 5.1 0.3 16.0 2.1
Coal mining 1.7 0.5 3.9 (1.1 )
Oil and gas (a) 17.4     0.2   (2.2 )   (0.6 )
Total Non-regulated Energy Group 24.2     1.0   17.7     0.4  
 
Corporate and Eliminations (b) (c) (4.2 )   (28.6 ) (14.0 )   (37.7 )
 
Income from continuing operations 34.6     (11.2 ) 57.6     21.6  
 
Income (loss) from discontinued operations, net of tax (c) (0.2 )   0.6   (6.8 )   2.5  
Net income (loss)   $ 34.5     $ (10.5 ) $ 50.8     $ 24.1  
 
(a)   Financial results for the three and nine months ended Sept. 30, 2012 include a $17.7 million after-tax gain on sale of our Williston Basin assets and the nine months ended Sept. 30, 2012 include a non-cash after-tax ceiling test impairment of $17.3 million.
(b) Financial results include a $0.4 million net after-tax non-cash mark-to-market gain and a $1.9 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2012, respectively, and a $24.9 million and $26.4 million net after-tax non-cash mark-to-market loss on interest rate swaps for the three and nine months ended Sept. 30, 2011, respectively.
(c) Certain indirect corporate costs and inter-segment interest expense 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 amount of $0.5 million for the three months ended Sept. 30, 2011, while after-tax indirect corporate costs and inter-segment interest expense not reclassified to discontinued operations for the nine months ended Sept. 30, 2012 and 2011 totaled $1.6 million and $1.5 million, respectively.
 
  Three Months Ended Sept. 30,   Nine Months Ended Sept. 30,
2012   2011 2012   2011
Weighted average common shares outstanding (in thousands):    
Basic 43,847 39,145 43,792 39,105
Diluted 44,108 39,145 44,026 39,792
 
Earnings per share:
Basic -
Continuing Operations $ 0.79 $ (0.29 ) $ 1.31 $ 0.55
Discontinued Operations     0.02   (0.16 )   0.07
Total Basic Earnings Per Share $ 0.79     $ (0.27 ) $ 1.15     $ 0.62
 
Diluted -
Continuing Operations $ 0.78 $ (0.29 ) $ 1.31 $ 0.54
Discontinued Operations     0.02   (0.16 )   0.07
Total Diluted Earnings Per Share $ 0.78     $ (0.27 ) $ 1.15     $ 0.61
 

DIVIDENDS

On Oct. 30, 2012, the company’s board of directors declared a quarterly dividend on common stock. Common shareholders of record at the close of business on Nov. 16, 2012 will receive $0.37 per share, equivalent to an annual dividend rate of $1.48 per share, payable on Dec. 1, 2012.

2012 EARNINGS GUIDANCE REAFFIRMED

Black Hills reaffirms expected 2012 earnings per share from continuing operations, as adjusted, to be in the range of $1.90 to $2.10, as previously issued on May 3, 2012. Assuming normal weather in the fourth quarter, earnings for the year are expected to be in the upper half of the guidance range.

2013 EARNINGS GUIDANCE INITIATED

Black Hills expects 2013 earnings per share from continuing operations, as adjusted, to be in the range of $2.20 to $2.40 per share based on the following assumptions:
  • Capital spending of $440 million to $470 million, including oil and gas capital expenditures of $90 million to $105 million;
  • Normal operations and weather conditions within our utility service territories that impact customer usage, and planned construction, maintenance and/or capital investment projects;
  • Successful completion of rate cases for electric and gas utilities;
  • No significant unplanned outages at any of our power generation facilities;
  • Oil and natural gas production in the range of 9.3 to 10.3 Bcf equivalent;
  • Oil and natural gas annual average NYMEX prices of $3.62 per MMBtu for natural gas and $91.78 per Bbl for oil; production-weighted average well-head prices of $2.56 per MMBtu and $81.61 per Bbl of oil, and average hedged prices received of $2.69 per MMBtu and $84.92 per Bbl;
  • Oil and natural gas depletion expense in the range of $1.35 to $1.55 per Mcfe;
  • Exclusion of mark-to-market changes on certain interest rate swaps;
  • No equity financing in 2013 except for approximately $3 million from the dividend reinvestment program; and
  • No significant acquisitions or divestitures.

CONFERENCE CALL AND WEBCAST

Black Hills Corp. will host a live conference call and webcast at 11 a.m. EST on Thursday, Nov. 8, 2012, 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 800-706-7741 if calling within the United States. International callers can call 617-614-3471. All callers need to enter the pass code 37156059 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 Thursday, Nov. 22, 2012, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 41048685.

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, are defined as Income (loss) from continuing operations and Net income (loss), adjusted for expenses, gains and losses 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. The 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 Sept. 30,   Nine Months Ended Sept. 30,
(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) $ 34.6     $ 0.78   $ (11.2 )   $ (0.29 ) $ 57.6     $ 1.31   $ 21.6     $ 0.54
Adjustments, after-tax:        
Unrealized (gain) loss on certain interest rate swaps (0.4 ) (0.01 ) 24.9 0.63 1.9 0.04 26.4 0.66
Ceiling test impairment 17.3 0.39
Gain on sale of Williston Basin assets (17.7 ) (0.40 ) (17.7 ) (0.40 )
Incentive compensation - Williston Basin sale 2.2 0.05 2.2 0.05
Credit facility fee write off 1.0 0.02
Rounding           0.01             0.01
Total adjustments (15.9 )   (0.36 ) 24.9     0.64   4.7     0.10   26.4     0.67
 
Income (loss) from continuing operations, as adjusted (non-GAAP) 18.7 0.42 13.7 0.35 62.3 1.41 48.0 1.21
Income (loss) from discontinued operations, net of tax (0.2 )     0.6     0.02   (6.8 )   (0.16 ) 2.5     0.07
Net income (loss), as adjusted (non-GAAP) $ 18.5     $ 0.42   $ 14.3     $ 0.37   $ 55.5     $ 1.25   $ 50.5     $ 1.28
 

BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months ended Sept. 30, 2012, compared to the three months ended Sept. 30, 2011, are discussed below. The following business group and segment information does not include certain intercompany 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 third quarter ended Sept. 30, 2012, was $14.6 million, compared to $16.4 million in 2011.

Electric Utilities
  Three Months Ended     Nine Months Ended  
Sept. 30, Variance Sept. 30, Variance
2012   2011   2012 vs. 2011   2012   2011   2012 vs. 2011
(in millions)
Gross margin $ 88.0     $ 80.6     $ 7.4   $ 261.7     $ 224.6     $ 37.1  
   
Operations and maintenance 34.1 34.8 (0.7 ) 110.2 106.1 4.1
Gain on sale of operating asset (0.8 ) 0.8 (0.8 ) 0.8
Depreciation and amortization 18.8     13.2     5.6   56.4     39.1     17.3  
Operating income 35.1 33.3 1.8 95.1 80.2 14.9
 
Interest expense, net (12.5 ) (9.7 ) (2.8 ) (38.1 ) (29.8 ) (8.3 )
Other (income) expense, net 0.2 0.2 1.2 0.6 0.6
Income tax benefit (expense) (8.2 )   (8.0 )   (0.2 ) (20.8 )   (16.4 )   (4.4 )
Income (loss) from continuing operations $ 14.6     $ 15.8     $ (1.2 ) $ 37.5     $ 34.7     $ 2.8  
 
  Three Months Ended Sept. 30,   Nine Months Ended Sept. 30,
2012   2011   2012   2011
Operating Statistics:    
Retail sales - MWh 1,230,266 1,232,679 3,475,472 3,456,841
Contracted wholesale sales - MWh 88,334 84,346 249,388 256,558
Off-system sales - MWh 288,528     395,769   1,171,198     1,253,385  
Total electric sales - MWh 1,607,128     1,712,794   4,896,058     4,966,784  
 
Total gas sales - Cheyenne Light - Dth 352,294 368,702 2,783,273 3,257,335
 
Regulated power plant availability:
Coal-fired plants (a) 95.4 % 95.1 % 89.1 % 91.6 %
Other plants 98.5 % 98.6 % 96.6 % 95.7 %
Total availability 97.0 % 96.4 % 93.0 % 93.1 %
 

(a) Nine months ended Sept. 30, 2012 reflects an unplanned outage due to a transformer failure and a planned outage at Neil Simpson II and a planned overhaul at Wygen II.

Third Quarter 2012 Compared with Third Quarter 2011

Gross margin increased primarily due to a $9.6 million increase related to rate adjustments that include a return on significant capital investments at Colorado Electric, partially offset by a $0.7 million decrease in wholesale and transmission margins as a result of decreased pricing, a decrease of $0.3 million in off-system sales and a decrease of $0.6 million from expiration of a reserve capacity agreement with PacifiCorp.

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

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 interest associated with the financing of the Pueblo generating facility completed in December 2011. Interest costs were capitalized during construction in the prior year.

Gas Utilities
  Three Months Ended     Nine Months Ended  
Sept. 30, Variance Sept. 30, Variance
2012   2011   2012 vs. 2011 2012   2011   2012 vs. 2011
(in millions)
Gross margin $ 39.3     $ 39.5     $ (0.2 ) $ 149.7     $ 163.4     $ (13.7 )
   
Operations and maintenance 28.3 28.3 88.1 91.1 (3.0 )
Depreciation and amortization 6.3     6.1     0.2   18.7     18.0     0.7  
Operating income 4.6 5.1 (0.5 ) 42.9 54.3 (11.4 )
 
Interest expense, net (5.4 ) (6.3 ) 0.9 (17.7 ) (19.6 ) 1.9
Other expense (income), net 0.1 0.2 (0.1 )
Income tax (expense) 0.8     1.8     (1.0 ) (8.9 )   (10.5 )   1.6  
Income (loss) from continuing operations $     $ 0.6     $ (0.6 ) $ 16.4     $ 24.3     $ (7.9 )
 
  Three Months Ended Sept. 30,   Nine Months Ended Sept. 30,
Operating Statistics: 2012   2011   2012   2011
   
Total gas sales - Dth 5,448,719 5,753,975 31,419,468 39,958,801
Total transport volumes - Dth 14,584,979 14,385,819 46,009,382 44,510,873
 

Third Quarter 2012 Compared with Third Quarter 2011

Operating income was comparable to the same period in the prior year reflecting normal seasonality of our Gas Utilities.

Interest expense, net decreased primarily due to lower interest rates.

Income tax benefit (expense): The deviation in the effective tax rate from the statutory rate is the result of a favorable true-up adjustment that had a more pronounced impact in 2012 due to significantly lower pre-tax net loss. The prior year also realized a favorable true up adjustment for flow-through treatment of certain property-related temporary differences.

Non-Regulated Energy Group

Income from continuing operations from the Non-regulated Energy group for the three months ended Sept. 30, 2012, was $24.2 million, compared to $1.0 million for the same period in 2011.

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.

Discontinued Operations

Third Quarter 2012 Compared with Third Quarter 2011

On Feb. 29, 2012, the company sold the outstanding stock of Enserco Energy Inc., our Energy Marketing segment, which resulted in this segment being reported as discontinued operations. Cash proceeds were approximately $166.3 million, subject to final post-closing adjustments. For comparative purposes, all prior results of our Energy Marketing segment have been restated to reflect the reclassification of this segment to discontinued operations on a consistent basis.

For the three months ended Sept. 30, 2012, we recorded a loss from discontinued operations of $0.2 million.

Pursuant to the provisions of the stock purchase agreement, the buyer requested purchase price adjustments totaling $7.2 million. We contested this proposed adjustment and estimated the amount owed at $1.4 million, which is accrued for in the loss from discontinued operations for the nine months ended Sept. 30, 2012. If we do not reach a negotiated agreement with the buyer regarding the purchase price adjustment, 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 2012 and 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 continue our continuous improvement program and cost-reduction efforts to mitigate the impacts of earnings challenges in the first quarter through the remainder of 2012;
  • Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings in periodic applications to recover costs for capital additions, 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;
  • 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.

(Minor differences may result due to rounding. Prior period information has been revised to reclassify information related to discontinued operations.)

  Consolidating Income Statement
            Electric   Power    
Utility Generation

 
Electric Gas Power Coal Oil and Inter-Co Inter-Co Other Inter-Co

Three Months Ended Sept. 30, 2012
Utilities   Utilities   Generation   Mining   Gas   Corporate   Lease Elim*   Lease Elim*   Eliminations   Total
(in millions)
Revenue $ 151.3 $ 63.4 $ 1.3 $ 6.1 $ 24.7 $ $ $ $ $ 246.8
Intercompany revenue 3.7 19.7 8.6 47.3 0.4 (79.7 )
Fuel, purchased power and cost of gas sold 67.0     24.2                     0.8         (29.4 )   62.6  
Gross Margin 88.0     39.2     21.0     14.7     24.7     47.3     (0.8 )   0.4     (50.3 )   184.2  
 
Operations and maintenance 34.1 28.3 7.8 10.8 12.1 46.8 (47.6 ) 92.3
Gain on sale of operating asset (27.3 ) (27.3 )
Depreciation, depletion and amortization 18.8 6.3 1.2 2.9 12.5 2.8 (3.3 ) 3.0 (2.8 ) 41.4
Impairment of long-lived assets                                      
Operating income 35.1     4.6     12.0     1.0     27.4     (2.3 )   2.5     (2.6 )   0.1     77.8  
 
Interest expense, net (13.6 ) (5.9 ) (3.2 ) (1.1 ) (20.5 ) 18.1 (26.2 )
Interest rate swaps - unrealized (loss) gain 0.6 0.6
Interest income 1.1 0.5 0.1 16.2 (17.5 ) 0.4
Other income (expense) 0.2 0.5 0.1 6.6 (7.4 )
Income tax benefit (expense) (8.2 )   0.8     (3.8 )   0.2     (9.0 )   2.0     (0.9 )   0.9         (18.0 )
Income (loss) from continuing operations   $ 14.6     $     $ 5.1     $ 1.7     $ 17.4     $ 2.6     $ 1.6     $ (1.7 )   $ (6.7 )   $ 34.6  
 

* 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 expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.
  Consolidating Income Statement
            Electric   Power    
Utility Generation Other

 
Electric Gas Power Coal Oil and Inter-Co Inter-Co Inter-Co

Nine Months Ended Sept. 30, 2012
Utilities   Utilities   Generation   Mining   Gas   Corporate   Lease Elim*   Lease Elim*   Eliminations   Total
(in millions)
Revenue $ 452.0 $ 314.3 $ 3.2 $ 18.5 $ 67.0 $ $ $ $ $ 855.0
Intercompany revenue 11.9 56.1 24.3 143.9 1.2 (237.4 )
Fuel, purchased power and cost of gas sold 202.2     164.6                 0.1     2.4         (86.1 )   283.2  
Gross margin 261.7     149.7     59.3     42.8     67.0     143.8     (2.4 )   1.2     (151.3 )   571.8  
 
Operations and maintenance 110.2 88.1 22.5 32.1 33.3 135.2 (139.0 ) 282.4
Gain on sale of operating asset (27.3 ) (27.3 )
Depreciation, depletion and amortization 56.4 18.7 3.4 9.6 34.8 8.1 (9.8 ) 8.2 (8.0 ) 121.4
Impairment of long-lived assets                 26.9                     26.9  
Operating income 95.1     42.9     33.4     1.1     (0.7 )   0.5     7.4     (7.0 )   (4.3 )   168.4  
 
Interest expense, net (44.8 ) (20.1 ) (12.3 ) (3.9 ) (64.0 ) 63.0 (82.1 )
Interest rate swaps - unrealized (loss) gain (2.9 ) (2.9 )
Interest income 6.8 2.4 0.5 1.2 48.0 (57.5 ) 1.4
Other income (expense) 1.2 0.1 2.0 0.2 30.3 (31.1 ) 2.7
Income tax benefit (expense) (20.8 )   (8.9 )   (5.6 )   (0.4 )   2.2     3.6     (2.7 )   2.5     0.2     (29.9 )
Income (loss) from continuing operations   $ 37.5     $ 16.4     $ 16.0     $ 3.9     $ (2.2 )   $ 15.5     $ 4.7     $ (4.5 )   $ (29.7 )   $ 57.6  
 

* 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 expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.
  Consolidating Income Statement

 
Electric   Gas   Power   Coal       Intercompany  

Three Months Ended Sept. 30, 2011
Utilities   Utilities   Generation   Mining   Oil and Gas  

Corporate (a)
  Eliminations   Total
(in millions)
Revenue $ 151.0 $ 72.7 $ 1.0 $ 9.2 $ 19.2 $ $ $ 253.1
Intercompany revenue 2.7 7.1 8.6 46.2 (68.2 ) (3.6 )
Fuel, purchased power and cost of gas sold 73.1     33.2                     (20.2 )   86.1  
Gross margin 80.6     39.5     8.1     17.8     19.2     46.2     (48.0 )   163.4  
 
Operations and maintenance 34.8 28.3 4.6 14.2 9.6 41.0 (42.0 ) 90.5
Depreciation, depletion and amortization 13.3     6.1     1.1     5.1     7.7     2.8     (2.8 )   33.3  
Operating income 33.3     5.1     2.4     (1.5 )   1.9     2.4     (4.0 )   39.6  
 
Interest expense, net (13.4 ) (7.8 ) (2.2 ) (1.5 ) (23.7 ) 25.8 (22.8 )
Interest rate swaps - unrealized (loss) gain (38.2 ) (38.2 )
Interest income 3.7 1.5 0.4 1.0 16.4 (22.5 ) 0.5
Other income (expense) 0.2 0.5 3.1 (3.1 ) 0.7
Income tax benefit (expense) (8.0 )   1.8     (0.3 )   0.5     (0.2 )   14.9     0.3     9.0  
Income (loss) from continuing operations   $ 15.8     $ 0.6     $ 0.3     $ 0.5     $ 0.2     $ (25.1 )   $ (3.5 )   $ (11.2 )
 
(a)   Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not reclassified to discontinued operations but included in the Corporate segment.
 
  Consolidating Income Statement

 
Electric   Gas   Power   Coal       Intercompany  

Nine Months Ended Sept. 30, 2011
Utilities   Utilities   Generation   Mining   Oil and Gas  

Corporate (a)
  Eliminations   Total
(in millions)
Revenue $ 431.6 $ 402.8 $ 2.6 $ 23.1 $ 55.9 $ $ $ 916.0
Intercompany revenue 9.9 20.9 25.8 142.1 (203.7 ) (5.0 )
Fuel, purchased power and cost of gas sold 216.9     239.4                 0.1     (55.9 )   400.5  
Gross margin 224.6     163.4     23.5     48.9     55.9     142.0     (147.8 )   510.5  
 
Operations and maintenance 106.1 91.1 12.9 41.8 30.3 125.8 (129.0 ) 279.0
Depreciation, depletion and amortization 39.1     18.0     3.1     14.4     22.6     8.2     (8.0 )   97.4  
Operating income 80.2     54.3     7.5     (7.3 )   3.0     8.0     (11.6 )   134.1  
 
Interest expense, net (40.5 ) (24.0 ) (6.6 ) (4.2 ) (69.0 ) 75.3 (69.0 )
Interest rate swaps - unrealized (loss) gain (40.6 ) (40.6 )
Interest income 10.7 4.3 1.2 2.9 46.8 (64.4 ) 1.5
Other income (expense) 0.6 0.2 1.1 1.7 (0.1 ) 32.9 (32.9 ) 3.5
Income tax benefit (expense) (16.4 )   (10.5 )   (1.1 )   1.6     0.7     17.5     0.3     (7.9 )
Income (loss) from continuing operations   $ 34.6     $ 24.3     $ 2.1     $ (1.1 )   $ (0.6 )   $ (4.4 )   $ (33.3 )   $ 21.6  
(a)   Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not reclassified to discontinued operations but included in the Corporate segment.

Copyright Business Wire 2010

If you liked this article you might like

Exelon, NRG Energy Could Be Impacted by Lower Power Prices Next Year

Exelon, NRG Energy Could Be Impacted by Lower Power Prices Next Year

New Lifetime High Reached By Black Hills (BKH)

New Lifetime High Reached By Black Hills (BKH)

Black Hills (BKH) Hits New Lifetime High Today

Black Hills (BKH) Hits New Lifetime High Today

Watch Out: Barbarians At The Gate For Black Hills (BKH)

Watch Out: Barbarians At The Gate For Black Hills (BKH)

Black Hills (BKH) Showing Signs Of Being Strong And Under The Radar

Black Hills (BKH) Showing Signs Of Being Strong And Under The Radar