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 November 3, 2015 - 5:15 PM EST
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Black Hills Corp. Reports Third Quarter 2015 Results and Provides 2016 Earnings Guidance

  • Adjusted EPS of $0.64 per share, a 5 percent increase compared to prior-year period
  • 2016 adjusted EPS guidance in range of $3.15 to $3.35 per share (excluding acquisition of SourceGas) 
  • SourceGas regulatory approval and integration processes on track
  • Electric Utilities delivered strong operational and financial results
  • Applications seeking approval for utility cost of service gas program filed
  • Company initiated process to explore potential sale of Colorado IPP assets

RAPID CITY, S.D., Nov. 03, 2015 (GLOBE NEWSWIRE) -- Black Hills Corp. (NYSE:BKH) today announced third-quarter 2015 financial results. Net income, as adjusted, was $29 million, or $0.64 per diluted share compared to net income, as adjusted of $27 million, or $0.61 per diluted share, for the same period in 2014 (this is a non-GAAP measure and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided). GAAP results for the third quarter 2015 were a loss of ($0.22) per share, including ($0.80) per share for a noncash impairment of crude oil and natural gas properties and ($0.06) per share related to external acquisition costs.

“We delivered strong operational performance in the third quarter and advanced our utility growth strategies,” said David R. Emery, chairman, president and CEO of Black Hills Corp. “Adjusted earnings per share increased 5 percent over the comparable prior-year period, highlighted by 22 percent earnings growth at our electric utilities and solid performance in our gas utilities, power generation and coal mine segments. Corporate-wide cost containment efforts continued and we made great progress toward our goal of being the safest energy company in the country, reporting the lowest trailing 12 month Total Case Incident Rate in the company’s recorded history.

“We are on track to close the SourceGas acquisition in the first half of next year. We filed joint applications for approvals in Arkansas, Colorado, Nebraska and Wyoming, and three of the states have established procedural schedules and hearing dates. An experienced leadership team has been guiding our integration and activities are well underway. We are excited about the complementary fit, future growth opportunities, and customer and shareholder benefits we expect from the transaction.

“We made progress on several key strategic initiatives to drive future earnings growth. We filed applications seeking approval for a cost of service gas program in six states and received approval from the Colorado Public Utilities Commission to purchase the $109 million, 60-megawatt Peak View Wind Project, which is expected to be completed by year-end 2016.

“Additionally, the company initiated a strategic review process to explore the sale of a minority interest in our Colorado IPP generating assets. Given the recent comparable transaction valuations for long-term contracted assets, we are optimistic that a premium valuation can be achieved for shareholders. Proceeds from any sale will be used to reduce the financing needs of the SourceGas acquisition.

“We began transitioning our oil and gas segment toward primarily serving our utilities through a cost of service gas program, while preserving the upside value potential of our oil and gas properties, particularly the Piceance Basin resources. We continued to manage through a challenging commodity price environment. Given our expectations of continued low energy prices, an additional noncash ceiling test impairment of our oil and gas properties is likely in the fourth quarter.

“This is an exciting time for Black Hills as we work toward closing the SourceGas acquisition. We remain focused on opportunities to better serve our customers and communities with safe and reliable service, and are well positioned to drive profitable growth and deliver long-term value to our shareholders,” Emery concluded.

    
  Three Months Ended September 30,  Nine Months Ended September 30,
(in millions, except per share amounts) 2015 2014 2015 2014
Non-GAAP:              
Net income, as adjusted (non-GAAP) $28.6  $27.4  $101.5  $96.4 
               
Earnings per share, as adjusted, diluted (non-GAAP) $0.64  $0.61  $2.28  $2.16 
               
GAAP:     
Net income (loss) $(9.9) $27.4  $(17.9) $96.4 
               
Earnings (loss) per share, diluted $(0.22) $0.61  $(0.40) $2.16 
                 

Black Hills Corp. highlights, recent regulatory filings and other updates include:

  • On July 12, the company entered into an agreement to acquire SourceGas Holdings LLC for total consideration of $1.89 billion. Joint applications for approval were filed on Aug. 10 with Arkansas, Colorado, Nebraska and Wyoming. On Aug. 18, the company received Hart-Scott-Rodino antitrust clearance for the acquisition. Procedural schedules have been established in Arkansas, Nebraska and Wyoming with hearings scheduled for January and February 2016. The transaction is expected to close in the first half of 2016.

  • Black Hills entered into a $1.17 billion bridge term loan to support the acquisition of SourceGas.

Utilities

  • Construction continued on a $65 million, 40-megawatt, natural gas-fired turbine at Colorado Electric’s Pueblo Airport Generating Station. The new turbine is expected to be in service by year-end 2016.

  • On Oct. 21, Colorado Electric received approval from the Colorado Public Utilities Commission to purchase the planned $109 million, 60-megawatt Peak View Wind Project, to be located near Colorado Electric's Busch Ranch wind farm. Construction is expected to commence in the second quarter 2016 and be completed by year-end 2016.

  • On Sept. 30, the company's utility subsidiaries submitted applications seeking approval for a cost of service gas program in Iowa, Kansas, Nebraska, South Dakota and Wyoming. A similar application was filed in Colorado on Nov. 2.

  • On July 27, Cheyenne Light, Fuel & Power recorded a new all-time electric peak load of 212 megawatts, its third new peak since June 1. The previous peak load of 198 megawatts was recorded on July 21, 2014.

  • On July 23, Black Hills Power received approval from the Wyoming Public Service Commission for a certificate of public convenience and necessity to construct a new 144-mile, $54 million electric transmission line from northeastern Wyoming to Rapid City, South Dakota. Black Hills Power received approval on Nov. 6, 2014, from the South Dakota Public Utilities Commission for a permit to construct this line. Assuming timely receipt of the remaining approvals, construction is expected to commence in the fourth quarter of 2015.

  • On July 1, the company closed the $17 million purchase of a natural gas utility with 6,700 customers in northwest Wyoming and certain nearby pipeline assets. The new gas utility customers were fully integrated onto Black Hills’ systems immediately upon closing of the transaction.

Non-regulated Energy

  • The company initiated a process to explore the sale of a minority interest in its Colorado IPP generating assets. If any resulting bids merit a sale, the transaction would be expected to close in the first quarter 2016.

  • The oil and gas business finished drilling the last of 13 horizontal Mancos Shale natural gas wells for its 2014/2015 southern Piceance Basin drilling program.  Six wells are on production and flowback operations are ongoing for three additional wells. Completion activities for the final four wells have been deferred.

  • The financial results for oil and gas were negatively impacted by lower average prices received for crude oil and natural gas, which decreased 27 percent and 37 percent, respectively, compared to the third quarter of 2014. Due to continued low commodity prices, the oil and gas segment recorded a $36 million after-tax noncash impairment of crude oil and natural gas properties for the quarter.

Corporate

  • On Oct. 27, Black Hills’ board of directors declared a quarterly dividend on the common stock. Shareholders of record at the close of business on Nov. 17, 2015, will receive $0.405 per share, equivalent to an annual dividend rate of $1.62 per share, payable on Dec. 1, 2015.

  • On Oct. 2, the company entered into $250 million of interest rate swaps to mitigate interest rate risk associated with planned future debt issuances.
    
BLACK HILLS CORPORATION
CONSOLIDATED FINANCIAL RESULTS
    
(Minor differences may result due to rounding.)
    
 Three Months Ended September 30, Nine Months Ended September 30,
 20152014 20152014
 (in millions)   
Net income (loss):     
Utilities:     
Electric$22.0  $18.2  $58.6  $44.2 
Gas1.6  1.6  27.0  28.3 
Total Utilities Group23.6  19.8  85.6  72.5 
            
Non-regulated Energy:     
Power generation9.1  7.8  24.8  23.1 
Coal mining3.0  2.6  9.1  7.1 
Oil and gas (a) (b)(39.8) (2.6) (130.1) (5.2)
Total Non-regulated Energy Group(27.7) 7.8  (96.2) 25.0 
            
Corporate and Eliminations (c)(5.9) (0.3) (7.3) (1.1)
            
Net income (loss)$(9.9) $27.4  $(17.9) $96.4 
                

(a) Financial results for the three and nine months ended September 30, 2015 included non-cash after-tax ceiling test impairments of $36 million and $113 million, respectively.
(b) Financial results for the nine months ended September 30, 2015 included a non-cash after-tax impairment to equity investments of $3.4 million.
(c) Financial results for the three and nine months ended September 30, 2015 included incremental, non-recurring acquisition costs (net of tax) of $2.8 million and $3.0 million respectively and after-tax internal labor costs attributable to the acquisition of $1.2 million and $1.8 million respectively.

    
 Three Months Ended September 30, Nine Months Ended September 30,
 20152014 20152014
Weighted average common shares outstanding (in thousands):       
Basic44,635  44,415  44,598  44,382 
Diluted44,635  44,608  44,598  44,584 
              
Earnings per share:     
Basic -     
Total Basic Earnings Per Share$(0.22) $0.62  $(0.40) $2.17 
              
Diluted -     
Total Diluted Earnings Per Share$(0.22) $0.61  $(0.40) $2.16 
                

EARNINGS GUIDANCE

Earnings per share, as adjusted is a non-GAAP financial measure. Earnings per share, as adjusted is defined as GAAP Earnings per share, adjusted for expenses and gains that the company believes do not reflect the company’s core operating performance.  Examples of these types of adjustments may include unique one-time non-budgeted events, impairment of assets, acquisition and disposition costs, and other adjustments noted in the earnings reconciliation table below.

2015 EARNINGS GUIDANCE REAFFIRMED

Black Hills reaffirms its guidance for 2015 earnings, as adjusted, of $2.90 to $3.10 per share (this is a non-GAAP measure and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided below).

        
2015 Earnings Guidance as Adjusted 
 LOW HIGH
(after-tax)       
Earnings (loss) per share (GAAP)$0.22  $0.42 
Adjustments, after-tax * :       
Ceiling test impairment 2.54   2.54 
Impairment of equity investments 0.08   0.08 
External acquisition costs 0.07   0.07 
Rounding (0.01)  (0.01)
Total adjustments 2.68   2.68 
        
Earnings (loss) per share, as adjusted (non-GAAP)  $2.90  $3.10 
        

* Additional adjustments may occur in the fourth quarter. Adjustments shown reflect the actual adjustments made for the first nine months of the year.

2016 EARNINGS GUIDANCE INITIATED**

Black Hills initiated guidance for 2016 earnings, as adjusted, to be in the range of $3.15 to $3.35 per share based on the following assumptions:

  • Excludes SourceGas acquisition, associated transaction costs and financing impacts;
  • Excludes potential sale of Colorado IPP assets;
  • Capital spending of $451 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 9.5 to 11.5 billion cubic feet equivalent;
  • Oil and natural gas annual average NYMEX prices of $3.00 per million British thermal units for natural gas and $50.00 per barrel for oil; production-weighted average well-head prices of $1.22 per MMBtu and $41.00 per Bbl of oil, and average hedged prices received of $1.54 per MMBtu and $54.73 per Bbl;
  • Oil and natural gas depletion expense in the range of $0.80 to $1.20 per million cubic feet equivalent;
  • No new debt or equity financing in excess of approximately $3 million from the dividend reinvestment program; and
  • No additional significant acquisitions or divestitures.

** The company is not able to provide a forward-looking quantitative GAAP to non-GAAP reconciliation for 2016 earnings guidance, as adjusted, because we do not know the unplanned or unique events that may occur.

CONFERENCE CALL AND WEBCAST

Black Hills will host a live conference call and webcast at 11 a.m. EST on Wednesday, Nov. 4, 2015, to discuss our 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 “Events and Presentations” 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 866-544-7741 if calling within the United States. International callers can call 724-498-4407. All callers need to enter the pass code 62191115 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 Wednesday, Nov. 18, 2015, at 855-859-2056 in the United States and at 404-537-3406 for international callers. The replay pass code is 62191115.

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 (GAAP), 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. Net income (loss), as adjusted, is defined as 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. The presentation of these non-GAAP financial measures should not be construed as an inference that future results will not be affected by unusual, non-routine, or non-recurring items.

Gross margin (revenue less cost of sales) is considered a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of operating performance. Gross margin for our Electric Utilities is calculated as operating revenue less cost of fuel, purchased power and cost of gas sold. Gross margin for our Gas Utilities is calculated as operating revenues less cost of gas sold. Our gross margin is impacted by the fluctuations in power purchases and natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to customers. Gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

                
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions, except per share amounts)2015 2014 2015 2014
(after-tax)Income EPS Income EPS Income EPS Income EPS
Net income (loss) (GAAP)$(9.9) $(0.22) $27.4  $0.61  $(17.9) $(0.40) $96.4  $2.16 
Adjustments, after-tax:               
Ceiling test impairment35.8  0.80      113.1  2.54     
Impairment of equity investments        3.4  0.08     
External acquisition costs2.8  0.06      3.0  0.07     
Rounding(0.1)       (0.1) (0.01)    
Total adjustments38.5  0.86      119.4  2.68     
                
Net income (loss), as adjusted (non-GAAP)  $28.6  $0.64  $27.4  $0.61  $101.5  $2.28  $96.4  $2.16 
                                

BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months ended September 30, 2015, compared to the three months ended September 30, 2014, are discussed below. The following business group and segment information does not include certain intercompany eliminations. Minor differences in comparative amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.

Utilities Group

Net income (loss) for the Utilities Group for the third quarter ended September 30, 2015, was $24 million, compared to $20 million in 2014.

Electric Utilities

  Three Months Ended
September 30,
Variance Nine Months Ended
September 30,
Variance
  201520142015 vs. 2014 201520142015 vs. 2014
  (in millions)    
Gross margin $111.5  $97.3  $14.2  $324.4  $280.9  $43.5 
                     
Operations and maintenance 43.7  39.1  4.6  131.5  121.9  9.6 
Depreciation and amortization   21.1  19.6  1.5  62.7  58.0  4.7 
Operating income 46.7  38.7  8.0  130.2  100.9  29.3 
         
Interest expense, net (13.1) (11.7) (1.4) (40.5) (35.6) (4.9)
Other (income) expense, net 0.6  0.3  0.3  0.8  0.9  (0.1)
Income tax benefit (expense) (12.2) (9.1) (3.1) (31.9) (22.2) (9.7)
Net income (loss) $22.0  $18.2  $3.8  $58.6  $44.2  $14.4 
                         


     
  Three Months Ended September 30,   Nine Months Ended September 30,
  20152014 20152014
Operating Statistics:      
Retail sales - MWh 1,345,749  1,250,486  3,752,535  3,563,216 
Contracted wholesale sales - MWh 65,952  83,714  215,119  250,941 
Off-system sales - MWh 188,844  234,009  770,199  833,833 
Total electric sales - MWh 1,600,545  1,568,209  4,737,853  4,647,990 
           
Total gas sales - Cheyenne Light - Dth 421,243  391,441  3,320,275  3,102,705 
           
Regulated power plant availability:      
Coal-fired plants (a) 89.0% 97.0% 92.2% 92.4%
Other plants  (b) (c) 96.4% 95.6% 95.3% 87.9%
Total availability 93.7% 96.2% 94.2% 89.8%
             

(a) Decrease was due to a planned annual outage at Wygen II during the three months ended September 30, 2015.
(b) The nine months ended September 30, 2014, included a planned outage at Ben French CT's #1 and #2 for a controls upgrade.
(c) The nine months ended September 30, 2014, reflected an unplanned outage due to a turbine bearing replacement and combustor upgrade at Pueblo Airport Generation Station.

Third Quarter 2015 Compared with Third Quarter 2014

Gross margin increased primarily due to a return on additional investment in our generating facilities which increased gross margins by $9.5 million compared to the same period in the prior year.  Cooling degree days increased by 36 percent compared to the same period in the prior year, and were 19 percent higher than normal, driving an increase of $3.3 million.  Electric margins were favorably impacted by higher retail load and demand that increased MWh sold, driving an increase of $1.7 million.  Gas gross margins at Cheyenne Light were favorably impacted by our MGTC and Energy West Wyoming system acquisitions increasing margins by $1.2 million.  Partially offsetting these increases was a $0.8 million decrease in technical service revenue from facility improvements at one of our large industrial customers in the prior year.

Operations and maintenance increased primarily due to costs related to Cheyenne Prairie, which was placed into commercial service on Oct. 1, 2014, an increase in property taxes and an increase in employee costs primarily from our Energy West Wyoming system acquisition.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of Cheyenne Prairie, which was placed into commercial service on Oct. 1, 2014.

Interest expense, net increased primarily due to interest costs from the $160 million of permanent financing placed during the fourth quarter of 2014 for Cheyenne Prairie.

Income tax benefit (expense): The effective tax rate was higher for the three months ended September 30, 2015 primarily due to an unfavorable true-up adjustment in the current year compared to the same period in the prior year.

Gas Utilities

       
  Three Months Ended
September 30,
Variance Nine Months Ended
September 30,
Variance
  201520142015 vs. 2014 201520142015 vs. 2014
  (in millions)    
Gross margin $42.4  $42.2  $0.2  $169.9  $173.6  $(3.7)
                     
Operations and maintenance 30.6  31.6  (1.0) 96.9  100.5  (3.6)
Depreciation and amortization 7.1  6.6  0.5  21.5  19.7  1.8 
Operating income 4.7  3.9  0.8  51.5  53.5  (2.0)
         
Interest expense, net (3.6) (3.8) 0.2  (11.0) (11.3) 0.3 
Other income (expense), net 0.6    0.6  0.6    0.6 
Income tax benefit (expense)   1.4  (1.4) (14.1) (13.8) (0.3)
Net income (loss) $1.6  $1.6  $  $27.0  $28.3  $(1.3)
                         


     
  Three Months Ended September 30,   Nine Months Ended September 30,
  20152014 20152014
Operating Statistics:      
Total gas sales - Dth 5,604,117 6,112,691  37,532,386 42,893,563 
Total transport volumes - Dth 14,725,979 14,360,388  49,444,612 50,385,306 
           

Third Quarter 2015 Compared with Third Quarter 2014

Gross margin was comparable to the same period in the prior year, reflecting a decrease of $1.0 million from milder weather and lower residential volumes sold, offset by base rate adjustments and riders at Kansas Gas, and increased transportation revenue. Heating degree days were 61 percent lower for the three months ended September 30, 2015, compared to the same period in the prior year and 57 percent lower than normal in the current year, compared to 6 percent higher than normal in the prior year.

Operations and maintenance decreased due to lower allowance for uncollectible account expense, lower employee costs and lower operating expenses.

Depreciation and amortization increased primarily due to a higher asset base than the same period in the prior year.

Other income (expense), net increased primarily due to a gain on the sale of land of $0.4 million.

Income tax benefit (expense): The effective tax rate for both periods presented was favorably impacted by a true-up adjustment attributable to the prior year.

Non-Regulated Energy Group

Net income (loss) from the Non-regulated Energy group for the three months ended September 30, 2015, was $(28) million, compared to Net income (loss) of $7.8 million for the same period in 2014.

Power Generation

       
  Three Months Ended
September 30,
Variance Nine Months Ended
September 30,
Variance
  201520142015 vs. 2014 201520142015 vs. 2014
  (in millions)    
Revenue $23.3  $22.0  $1.3  $68.2  $66.3  $1.9 
                     
Operations and maintenance 7.5  7.3  0.2  23.8  23.7  0.1 
Depreciation and amortization 1.1  1.1    3.3  3.5  (0.2)
Operating income 14.7  13.6  1.1  41.1  39.1  2.0 
         
Interest expense, net (0.8) (0.9) 0.1  (2.4) (2.8) 0.4 
Other (income) expense, net            
Income tax benefit (expense) (4.9) (4.9)   (14.0) (13.3) (0.7)
Net income (loss) $9.1  $7.8  $1.3  $24.8  $23.1  $1.7 
                         


     
  Three Months Ended September 30, Nine Months Ended September 30,
  20152014 20152014
Operating Statistics:      
Contracted fleet power plant availability -      
Coal-fired plants 98.9%96.1% 98.2%98.0%
Gas-fired plants 99.2%99.2% 99.0%98.7%
Total availability 99.1%98.5% 98.8%98.6%
           

Third Quarter 2015 Compared with Third Quarter 2014

Revenue increased primarily due to an increase in PPA pricing and an increase in fired-hours and MWh sold, partially offset by a decrease in off-system sales.

Operations and maintenance was comparable to the same period in the prior year.

Depreciation and amortization was comparable to the same period in the prior year. The generating facility located in Pueblo, Colorado, is accounted for as a capital lease under GAAP; therefore, depreciation expense for the original cost of the facility is recorded at the Electric Utility segment.

Income tax benefit (expense): The effective tax rate was lower in 2015 primarily due to true-up adjustment related to the prior year filed tax return.

Coal Mining

  Three Months Ended
September 30,
Variance Nine Months Ended
September 30,
Variance
  201520142015 vs. 2014 201520142015 vs. 2014
  (in millions)    
Revenue $17.0  $15.6  $1.4  $49.6  $45.7  $3.9 
                     
Operations and maintenance 10.8  9.9  0.9  31.4  30.0  1.4 
Depreciation, depletion and amortization 2.5  2.5    7.4  7.8  (0.4)
Operating income (loss) 3.6  3.2  0.4  10.8  7.9  2.9 
         
Interest (expense) income, net (0.1) (0.1)   (0.3) (0.3)  
Other income (expense), net 0.6  0.5  0.1  1.7  1.7   
Income tax benefit (expense) (1.1) (0.9) (0.2) (3.1) (2.2) (0.9)
Net income (loss) $3.0  $2.6  $0.4  $9.1  $7.1  $2.0 
                         


     
  Three Months Ended September 30, Nine Months Ended September 30,
  20152014 20152014
Operating Statistics: (in thousands)   
Tons of coal sold 1,041 1,082  3,136 3,232 
Cubic yards of overburden moved 1,747 1,005  4,552 2,925 
       
Revenue per ton $16.30 $14.38  $15.82 $14.15 
               

Third Quarter 2015 Compared with Third Quarter 2014

Revenue increased primarily due to a 13 percent increase in price per ton sold, partially offset by a 4 percent decrease in tons sold. The increase in pricing was driven by the price re-opener on a coal contract with the third-party operator of the Wyodak plant which became effective in the third quarter of 2014, partially offset by contract price adjustments based on actual mining costs.  Approximately 50 percent of the mine's production is sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased primarily due to materials and outside services for major maintenance on processing equipment and an increase in royalties driven by increased revenues, partially offset by lower fuel costs.

Income tax benefit (expense): The effective tax rate was comparable to the same period in the prior year. 

Oil and Gas

       
  Three Months Ended
September 30,
Variance Nine Months Ended
September 30,
Variance
  201520142015 vs. 2014 201520142015 vs. 2014
  (in millions)    
Revenue $9.9  $13.5  $(3.6) $33.5  $43.5  $(10.0)
                     
Operations and maintenance 11.0  10.3  0.7  32.9  31.7  1.2 
Depreciation, depletion and amortization 6.2  6.7  (0.5) 22.5  19.0  3.5 
Impairment of long-lived assets 61.9    61.9  178.4    178.4 
Operating income (loss) (69.1) (3.6) (65.5) (200.2) (7.3) (192.9)
         
Interest income (expense), net (0.7) (0.4) (0.3) (1.6) (1.3) (0.3)
Other (income) expense, net (0.2)   (0.2) (0.4) 0.1  (0.5)
Impairment of equity investments       (5.2)   (5.2)
Income tax benefit (expense) 30.2  1.4  28.8  77.3  3.2  74.1 
Net income (loss) $(39.8) $(2.6) $(37.2) $(130.1) $(5.2) $(124.9)
                         


      
  Three Months Ended
September 30,
Percentage
Increase
Nine Months Ended
September 30,
Percentage
Increase
  20152014 (Decrease) 20152014 (Decrease)
Operating Statistics:               
Bbls of crude oil sold 98,722 82,640  19% 278,357 249,130  12%
Mcf of natural gas sold 2,271,186 1,856,138  22% 7,226,949 5,456,928  32%
Bbls of NGL sold 19,342 33,035  (41)% 81,383 102,079  (20)%
Mcf equivalent sales 2,979,568 2,550,187  17% 9,385,391 7,564,179  24%
        
Depletion expense/Mcfe $1.64 $2.15  (24)% $2.03 $2.02  %
        
Average hedged price received (a)(b)       
Crude Oil (Bbl) $58.31 $80.42  (27)% $63.20 $83.19  (24)%
Natural Gas (MMcf) $1.69 $2.70  (37)% $1.89 $3.07  (38)%
Natural Gas Liquids (Bbl) $2.87 $35.78  (92)% $13.64 $38.46  (65)%
        
Average well-head price       
Crude Oil (Bbl) $40.31 $85.15  (53)% $42.83 $88.18  (51)%
Natural Gas (MMcf) $0.82 $1.73  (53)% $0.89 $2.57  (65)%
                     


(a) Net of hedge settlement gains and losses.
(b) Ceiling test impairments of $62 million and $178 million were recorded for the three and nine months ended September 30, 2015.  If crude oil and natural gas prices remain at or near the current levels, additional ceiling impairment charges could occur in 2015.

Third Quarter 2015 Compared with Third Quarter 2014

Revenue decreased primarily due to lower commodity prices for both crude oil and natural gas, resulting in a 27 percent decrease in the average hedged price received for crude oil sold, and a 37 percent decrease in the average hedged price received for natural gas sold. A production increase of 17 percent, driven primarily by three new Piceance Mancos Shale wells placed on production in the third quarter of 2015, partially offset the decrease in prices.

Operations and maintenance increased primarily due to severance costs, partially offset by lower production taxes and ad valorem taxes on lower revenue.

Depreciation, depletion and amortization decreased primarily due to the reduction in our full cost pool as a result of the impact from the ceiling test impairments incurred in the current year, partially offset by the depletion rate applied to greater production.

Impairment of long-lived assets represents a noncash write-down in the value of our natural gas and crude oil properties driven by low natural gas and crude oil prices. The write-down reflected a 12 month average NYMEX price of $3.06 per Mcf, adjusted to $1.72 per Mcf at the wellhead, for natural gas, and $59.21 per barrel, adjusted to $52.82 per barrel at the wellhead, for crude oil.

Income tax (expense) benefit: Each period presented reflects a tax benefit.  The effective tax rate for 2015 was impacted by a favorable true-up adjustment.

Corporate Activities

Third Quarter 2015 Compared with Third Quarter 2014

Net loss for Corporate activity was $5.9 million for the three months ended September 30, 2015, compared to net loss of $0.3 million for the three months ended September 30, 2014. The variance from the prior year was due to higher corporate expenses, primarily driven by costs related to the SourceGas acquisition, including approximately $3.0 million of bridge financing costs recognized in interest expense and approximately $1.8 million in labor attributed to the acquisition during the three months ended September 30, 2015, compared to the three months ended September 30, 2014. 

ABOUT BLACK HILLS CORP.

Black Hills Corp. (NYSE:BKH) is a growth-oriented, vertically-integrated energy company with a tradition of improving life with energy and a vision to be the energy partner of choice. Based in Rapid City, South Dakota, the company serves 792,000 natural gas and electric utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company also generates wholesale electricity and produces natural gas, crude oil and coal. Black Hills Corp.'s more than 2,000 employees form partnerships and produce positive results for our customers, communities and shareholders. 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 2015 and 2016 earnings guidance and anticipated benefits of the acquisition of SourceGas Holdings LLC. 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 2014 Annual Report on Form 10-K, Item 1A of Part II of our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015, 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 regulatory approvals for the SourceGas acquisition and to successfully close and implement the transaction;

  • Our ability to obtain regulatory approval to implement a cost of service gas program;

  • 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, plant retirements and decommissioning, fuel, transmission, purchased power, and other operating costs and the timing in which new rates would go into effect;

  • Our ability to complete our capital program in a cost-effective and timely manner;

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

  • The impact of the volatility and extent of changes in commodity prices on our earnings and the underlying value of our oil and gas assets, including the possibility that we may be required to take impairment charges under the SEC's full cost ceiling test for natural gas and oil reserves; 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.)

  
 Consolidating Income Statement
Three Months Ended September 30, 2015Electric
Utilities (a)
 Gas
Utilities
 Power
Generation (a)
 Coal
Mining
 Oil and
Gas
 Corporate Electric
Utility
Inter-Co
Lease Elim (a)
 Power
Generation
Inter-Co
Lease Elim (a)
  Other
Inter-Co
Eliminations
  Total
                                        
 (in millions)
Revenue$182.3  $68.9  $2.1  $8.9  $9.9  $  $  $  $  $272.1 
Intercompany revenue2.5    21.1  8.1    56.1    0.6  (88.5)  
Fuel, purchased power and cost of gas sold  73.4  26.6          1.2    (29.5) 71.6 
Gross margin111.5  42.4  23.3  17.0  9.9  56.1  (1.2) 0.6  (58.9) 200.5 
                                      
Operations and maintenance43.7  30.6  7.5  10.8  11.0  54.9      (55.5) 102.9 
Depreciation, depletion and amortization21.1  7.1  1.1  2.5  6.2  2.3  (3.3) 3.1  (2.3) 37.8 
Impairment of long-lived assets        61.9          61.9 
Operating income (loss)46.7  4.7  14.7  3.6  (69.1) (1.1) 2.1  (2.5) (1.1) (2.0)
                                      
Interest expense, net(14.2) (3.8) (1.0) (0.1) (0.7) (17.1)     15.3  (21.6)
Interest income1.2  0.1  0.3      12.2      (13.4) 0.4 
Other income (expense)0.6  0.6    0.6  (0.2) 14.0      (14.3) 1.3 
Impairment of equity investments                   
Income tax benefit (expense)(12.2)   (4.9) (1.1) 30.2  (0.1) (0.8) 0.9    12.0 
Net income (loss)$22.0  $1.6  $9.1  $3.0  $(39.8) $7.8  $1.3  $(1.6) $(13.5) $(9.9)
                                        

(a) The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station 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
Nine Months Ended September 30, 2015Electric
Utilities (a)
 Gas
Utilities
 Power
Generation (a)
 Coal
Mining
 Oil and
Gas
 Corporate Electric
Utility
Inter-Co
Lease Elim (a)
 Power
Generation
Inter-Co
Lease Elim (a)
 Other
Inter-Co
Eliminations
 Total
                                        
 (in millions)
Revenue$535.0  $386.0  $5.8  $26.1  $33.5  $  $  $  $  $986.3 
Intercompany revenue8.5    62.5  23.5    169.0    1.8  (265.2)  
Fuel, purchased power and cost of gas sold  219.1  216.1        0.1  3.5    (87.9) 350.8 
Gross margin324.4  169.9  68.2  49.6  33.5  168.9  (3.5) 1.8  (177.3) 635.6 
                                      
Operations and maintenance131.5  96.9  23.8  31.4  32.9  163.9      (169.5) 310.8 
Depreciation, depletion and amortization62.7  21.5  3.3  7.4  22.5  6.6  (9.8) 9.2  (6.6) 116.8 
Impairment of long-lived assets        178.4          178.4 
Operating income (loss)130.2  51.5  41.1  10.8  (200.2) (1.6) 6.4  (7.4) (1.2) 29.6 
                                      
Interest expense, net(43.6) (11.5) (3.1) (0.3) (1.8) (41.8)     42.1  (60.0)
Interest income3.1  0.4  0.7    0.2  36.0      (39.3) 1.2 
Other income (expense)0.8  0.6    1.7  (0.4) 53.4      (54.4) 1.8 
Impairment of equity investments        (5.2)         (5.2)
Income tax benefit (expense)(31.9) (14.1) (14.0) (3.1) 77.3  0.1  (2.3) 2.7    14.6 
Net income (loss)$58.6  $27.0  $24.8  $9.1  $(130.1) $46.1  $4.0  $(4.7) $(52.8) $(17.9)
                                        


  
 Consolidating Income Statement
Three Months Ended September 30, 2014Electric
Utilities (a)
 Gas
Utilities
 Power
Generation (a)
 Coal
Mining
 Oil and
Gas
 Corporate Electric
Utility
Inter-Co
Lease Elim (a)
 Power
Generation
Inter-Co
Lease Elim (a)
 Other
Inter-Co
Eliminations
 Total
                                        
 (in millions)
Revenue$171.4  $78.7  $1.6  $6.9  $13.5  $  $  $  $  $272.1 
Intercompany revenue3.2    20.4  8.7    52.4    0.5  (85.2)  
Fuel, purchased power and cost of gas sold  77.2  36.5          1.1    (30.1) 84.7 
Gross margin97.3  42.2  22.0  15.6  13.5  52.4  (1.1) 0.5  (55.1) 187.4 
                                      
Operations and maintenance39.1  31.6  7.3  9.9  10.3  50.5      (53.2) 95.5 
Depreciation, depletion and amortization19.6  6.6  1.1  2.5  6.7  2.0  (3.3) 3.2  (2.0) 36.6 
Operating income (loss)38.7  3.9  13.6  3.2  (3.6) (0.1) 2.2  (2.7) 0.1  55.2 
                                      
Interest expense, net(12.8) (3.8) (1.1) (0.1) (0.6) (12.5)     13.5  (17.4)
Interest income1.1    0.2    0.2  12.2      (13.2) 0.6 
Other income (expense)0.3      0.5    9.8      (10.1) 0.6 
Income tax benefit (expense)(9.1) 1.4  (4.9) (0.9) 1.4  0.3  (0.8) 1.0    (11.6)
Net income (loss)$18.2  $1.6  $7.8  $2.6  $(2.6) $9.7  $1.4  $(1.7) $(9.7) $27.4 
                                        

(a) The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station 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
Nine Months Ended September 30, 2014Electric
Utilities (a)
 Gas
Utilities
 Power
Generation (a)
 Coal
Mining
 Oil and
Gas
 Corporate Electric
Utility
Inter-Co
Lease Elim (a)
 Power
Generation
Inter-Co
Lease Elim (a)
 Other
Inter-Co
Eliminations
 Total
                                        
 (in millions)
Revenue$508.2  $440.6  $4.1  $19.1  $43.5  $  $  $  $  $1,015.5 
Intercompany revenue10.3    62.2  26.6    164.6    1.5  (265.3)  
Fuel, purchased power and cost of gas sold  237.7  266.9        0.1  3.1    (91.3) 416.5 
Gross margin280.9  173.6  66.3  45.7  43.5  164.5  (3.1) 1.5  (174.0) 599.0 
                                      
Operations and maintenance121.9  100.5  23.7  30.0  31.7  157.9      (167.5) 298.2 
Depreciation, depletion and amortization58.0  19.7  3.5  7.8  19.0  5.5  (9.8) 9.6  (5.5) 107.8 
Operating income (loss)100.9  53.5  39.1  7.9  (7.3) 1.1  6.7  (8.0) (0.9) 193.1 
                                      
Interest expense, net(39.2) (11.8) (3.3) (0.4) (2.0) (38.0)     42.6  (52.1)
Interest income3.6  0.4  0.5    0.7  37.0      (40.8) 1.5 
Other income (expense)0.9      1.7  0.1  43.1      (43.8) 2.1 
Income tax benefit (expense)(22.2) (13.8) (13.3) (2.2) 3.2  (0.6) (2.5) 3.0  0.1  (48.3)
Net income (loss)$44.2  $28.3  $23.1  $7.1  $(5.2) $42.6  $4.3  $(5.1) $(42.9) $96.4 
                                        
Investor Relations:	
Jerome E. Nichols	
Phone 605-721-1171
Email	investorrelations@blackhillscorp.com
	
Media Contact:	
24-hour Media Assistance 866-243-9002

Source: GlobeNewswire (November 3, 2015 - 5:15 PM EST)

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