May 12 - Black Hills Corp. Reports 2012 First Quarter Results and Revises Guidance

Source Press Release
Company Black Hills Corp 
Tags Coal, Power, Financial & Operating Data
Date May 03, 2012

Black Hills Corp. announced 2012 first quarter financial results. Income from continuing operations, as adjusted, was $28.5 million, or $0.65 per diluted share, compared to $25.6 million, or $0.64 per diluted share, for the same period in 2011.

“Several key strategic projects reached milestones in the quarter” .“We are pleased with our overall financial and operating results in the first quarter considering the record-breaking warm temperatures in our utility service territories and the lowest natural gas prices since 2001,” said David R. Emery, chairman, president and chief executive officer of Black Hills Corp. “Earnings increased due to the commencement of operations at our new power plant complex near Pueblo, Colo., a 23 percent increase in oil and gas sales volumes and improvements in our coal mining segment. These gains partially offset the approximately $0.13 per share negative earnings impact from lower residential and commercial energy demand in our electric and gas utilities as compared to last year and a 22 percent decrease in our average price received for natural gas.

“We are working diligently, through our rigorous continuous improvement program and cost-reduction efforts, to mitigate the impacts of the unseasonably warm winter and our expectations of sustained low natural gas prices for the remainder of 2012. Based on our analysis, these initiatives will offset most of the first quarter impact of warm weather in our utilities but will be not be enough to offset the impacts of sustained low natural gas prices. As a result, we are revising our earnings guidance range to $1.90 to $2.10 per share, as adjusted, from continuing operations to more accurately reflect the financial results we expect our businesses to deliver in 2012.”

Three Months Ended March 31, 
(in millions, except per share amounts)    2012    2011 
Non-GAAP *:         
Income from continuing operations, as adjusted    28.5      25.6   
Income (loss) from discontinued operations, net of tax    (5.5    (2.2 
Net income, as adjusted (non-GAAP)    23.0      23.4   
         
Earnings per share from continuing operations, as adjusted, diluted    0.65      0.64   
Earnings (loss) per share, discontinued operations, net of tax    (0.12    (0.05 
Earnings per share, diluted, as adjusted (non-GAAP)    0.53      0.59   
         
GAAP:         
Income from continuing operations    35.3      29.1   
Income (loss) from discontinued operations, net of tax    (5.5    (2.2 
Net income    29.8      26.9   
         
Earnings per share from continuing operations, diluted    0.80      0.73   
Income (loss) from discontinued operations, net of tax    (0.12    (0.05 
Earnings per share, diluted    0.68      0.68   
                 

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

“Several key strategic projects reached milestones in the quarter,” Emery said. “We received all remaining permits and started construction on our 29 megawatt wind project for Colorado Electric. The permitting and regulatory processes continued for the new $237 million, 132 megawatt natural gas-fired generating facility for our Cheyenne Light, Fuel & Power and Black Hills Power utilities. In addition, we made progress on our Cheyenne Light electric and gas rate cases.

“On Feb. 29, 2012, we closed the transaction to sell all of the outstanding stock in our Energy Marketing business, Enserco Energy Inc., significantly reducing our risk profile and improving our credit metrics. Net cash proceeds were $166.3 million, subject to final post-closing adjustments that are expected in the second quarter of 2012.”

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

Utilities

  • Colorado Electric’s new $230 million, 180 megawatt power plant near Pueblo, Colo. began commercial operations and started serving utility customers on Jan. 1, 2012. New rates for Colorado Electric reflecting the new power plant investment were also implemented on Jan. 1.
  • Colorado Electric received final permits and rights-of-way for the construction of a 29 megawatt wind turbine project south of Pueblo, Colo. Construction for this project has commenced, and will require a net capital investment of $27 million for the utility's 50 percent share of the project. The project is expected to be operational no later than Dec. 31, 2012.
  • Colorado Electric’s request for a certificate of public convenience and necessity to construct a third utility-owned, 88 megawatt natural gas-fired turbine at the existing Pueblo Airport generating location was denied when the Colorado Public Utilities Commission issued its final order on April 13, 2012. Colorado Electric retains the right under the Colorado Clean Air – Clean Jobs Act to own the 42 megawatts of replacement generation for the W.N. Clark plant that is required to be retired by Dec. 13, 2013. Colorado Electric is expected to file an electric resource plan by July 30, 2012, that will identify an alternative replacement resource for the W.N. Clark plant.
  • Cheyenne Light and Black Hills Power filed a joint request with the Wyoming Public Service Commission on Nov. 1, 2011, for a certificate of public convenience and necessity to construct and operate a new $237 million, 132 megawatt natural gas-fired electric generating facility and related gas and electric transmission. A procedural schedule has been published, and a public hearing with the Wyoming Public Service Commission is scheduled for July 31, 2012, and Aug. 1, 2012.
  • Cheyenne Light filed requests with the Wyoming Public Service Commission on Dec. 2, 2011, for electric and natural gas revenue increases. Cheyenne Light is seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue. A procedural schedule has been published, and a public hearing with the Wyoming Public Service Commission is scheduled for the week of June 18, 2012.

Non-regulated Energy

  • Black Hills Colorado IPP’s new $261 million, 200 megawatt power plant near Pueblo, Colo., began commercial operations on Jan. 1, 2012, with its output sold to Colorado Electric under a 20-year power purchase agreement.
  • The Coal Mining segment’s unprofitable train load-out coal contract expired at year end. In addition, the mine received all necessary permits and approval for its revised mine plan. The revised plan will relocate mining operations to an area in the mine with lower overburden and shorter haul distances, reducing overall mining costs.
  • Oil and Gas reported a 23 percent increase in total sales volumes, reflecting a 40 percent increase in crude oil and a 19 percent increase in natural gas. Additional activity from our non-operated interests in the Bakken was responsible for the crude oil volume gains and the Mancos shale test wells drove the higher natural gas volumes.

Corporate

  • On Feb. 1, 2012, the company entered into a new $500 million corporate revolving credit facility for five years at favorable terms.
  • On April 24, 2012, Black Hills Corp. declared a quarterly dividend of $0.37 per share. We have increased our dividend for 42 consecutive years. Only two other electric or gas utility companies in the United States have a longer history of annual dividend increases.

Discontinued Operations

  • On Feb. 29, 2012, the company sold the outstanding stock of its Energy Marketing business, Enserco Energy Inc. Cash proceeds from the transaction were $166.3 million, with final post-closing adjustments expected to be settled during the second quarter of 2012. The company recorded a loss, net of tax, of $1.6 million during the quarter, including $2.2 million in transaction costs, net of tax..
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 March 31, 
    2012    2011 
Net income (loss):         
Utilities:         
Electric    8.7      10.2   
Gas    15.2      19.3   
Total Utilities Group    23.9      29.5   
         
Non-regulated Energy:         
Power generation    6.9      1.2   
Coal mining    1.0      (1.3 
Oil and gas    —      (0.7 
Total Non-regulated Energy Group    7.9      (0.8 
         
Corporate and Eliminations (a) (b)    3.4      0.4   
         
Income from continuing operations    35.3      29.1   
         
Income (loss) from discontinued operations, net of tax (b)    (5.5    (2.2 
Net income (loss)    29.8      26.9   
                 
(a)    Financial results for the three months ended March 31, 2012 and 2011 include a non-cash after-tax gain related to mark-to-market adjustments on certain interest rate swaps of $7.8 million and $3.6 million, respectively. 
(b)    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 $1.6 million and $0.5 million for the three months ended March 31, 2012 and 2011, respectively. 
     
    Three Months Ended March 31, 
    2012    2011 
Weighted average common shares outstanding (in thousands):         
Basic    43,731      39,059   
Diluted    43,969      39,761   
         
Earnings per share:         
Basic -          
Continuing Operations    0.81      0.74   
Discontinued Operations    (0.13    (0.05 
Total Basic Earnings Per Share    0.68      0.69   
         
Diluted -          
Continuing Operations    0.80      0.73   
Discontinued Operations    (0.12    (0.05 
Total Diluted Earnings Per Share    0.68      0.68   
                 

EARNINGS GUIDANCE REVISED

Black Hills now expects its 2012 earnings per share, as adjusted, from continuing operations to be in the range of $1.90 to $2.10 versus the $2.00 to $2.20 earnings per share range most recently issued on Feb. 7, 2012. The revised guidance range reflects the earnings impacts from warmer-than-normal weather in the company’s utility service territories during the first quarter and its expectation of sustained low natural gas prices for the remainder of 2012. It is expected the company’s cost-reduction efforts and continuous improvement initiatives will offset the financial impact of the unseasonable weather but will not alleviate the impact associated with sustained low natural gas prices.

The revised guidance range is based on the following updated key assumptions:

  • Normal operations and weather conditions within our utility service territories for the remainder of the year;
  • Successful completion of rate cases for electric and gas utilities;
  • No significant unplanned outages at any of our power generation facilities;
  • Anticipated capital expenditures of $375 million to $400 million, including $70 million to $90 million for oil and gas;
  • Oil and natural gas production in the range of 8.7 to 9.7 Bcfe for the remaining nine months and 12.0 to 13.0 Bcfe for the year;
  • Oil and gas average NYMEX prices of $2.89 per MMBtu for natural gas and $106.75 per Bbl for oil; production-weighted average well-head prices of $1.79 per Mcf and $93.59 per Bbl of oil, all based on forward strips, and average hedged prices of $2.70 per Mcf and $88.24 per Bbl for the remaining nine months of the year;
  • Excludes potential $45 million to $55 million oil and gas ceilings test impairment assuming natural gas prices remain at approximately $2.00 per MMBtu for the balance of 2012;
  • Success of cost-reduction programs and other initiatives to improve performance;
  • Exclusion of mark-to-market changes on $250 million of certain interest rate swaps;
  • Financing plans to maintain appropriate capital structure;
  • Approximately $3 million of equity financing from the dividend reinvestment program; and
  • No additional significant acquisitions or divestitures

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, as adjusted, is defined as Income (loss) from continuing operations and Net income, 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 March 31, 
(In millions, except per share amounts)    2012    2011 
(after-tax)    Income    EPS    Income    EPS 
Income (loss) from continuing operations (GAAP)    35.3      0.80      29.1      0.73   
Adjustments, after-tax:                 
Unrealized (gain) loss on certain interest rate swaps    (7.8    (0.18    (3.5    (0.09 
Credit facility fee write off    1.0      0.02      —      —   
Rounding    —      0.01      —      —   
Total adjustments    (6.8    (0.15    (3.5    (0.09 
                 
Income (loss) from continuing operations, as adjusted (non-GAAP)    28.5      0.65      25.6      0.64   
Income (loss) from discontinued operations, net of tax    (5.5    (0.12    (2.2    (0.05 
Net income (loss), as adjusted (non-GAAP)    23.0      0.53      23.4      0.59   
                                 

DIVIDENDS

On April 24, 2012, our board of directors declared a quarterly dividend on common stock. Common shareholders of record at the close of business on May 18, 2012, will receive $0.37 per share, equivalent to an annual dividend rate of $1.48 per share, payable on June 1, 2012.

BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months ended March 31, 2012, compared to the three months ended March 31, 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 first quarter ended March 31, 2012, was $24.0 million, compared to $29.5 million in 2011.

Electric Utilities

    Three Months Ended     
    March 31,    Variance 
    2012    2011    2012 vs. 2011 
    (in millions) 
Gross margin    85.5      74.2      11.3   
             
Operations and maintenance    39.2      37.1      2.1   
Depreciation and amortization    18.9      12.8      6.1   
Operating income    27.3      24.3      3.0   
             
Interest expense, net    (13.2    (9.9    (3.3 
Other (income) expense, net    0.7      0.4      0.3   
Income tax benefit (expense)    (6.0    (4.5    (1.5 
Income (loss) from continuing operations    8.7      10.2      (1.5 
                         
    Three Months Ended March 31, 
    2012    2011 
Operating Statistics:         
Retail sales - MWh    1,118,810      1,146,182   
Contracted wholesale sales - MWh    89,048      89,959   
Off-system sales - MWh    527,547      404,844   
Total electric sales - MWh    1,735,405      1,640,985   
         
 Total gas sales - Cheyenne Light - Dth             1,787,758      1,948,705   
         
Regulated power plant availability:         
Coal-fired plants (a)    90.8    91.3 
Other plants    95.0    98.6 
Total availability    92.9    93.9 
             

(a) 2012 reflects planned overhauls at Wygen II. 2011 reflects a major overhaul and an unplanned outage at the PacifiCorp-operated Wyodak plant.

First Quarter 2012 Compared to First Quarter 2011

Gross margin increased primarily due to a $9.3 million increase related to rate adjustments that include a return on significant capital investments specifically at Colorado Electric, $0.6 million increase in off-system sales mainly from higher quantities sold, partially offset by a $2.8 million decrease in quantities sold as a result of lower customer demand.

Operations and maintenance increased primarily due to higher property taxes and increased corporate allocations resulting from the generating facility in Pueblo, Colo., partially offset by lower maintenance costs.

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

Interest expense, net increased primarily due to lower capitalized interest associated with the completed construction of the Pueblo generating facility in Dec. 2011.

Income tax: The effective tax rate increased due to unfavorable state income tax true-up adjustments and the impact of research and development credits not being renewed.

Gas Utilities

    Three Months Ended     
    March 31,    Variance 
    2012    2011    2012 vs. 2011 
    (in millions) 
Gross margin    68.5      77.1      (8.6 
             
Operations and maintenance    31.3      34.6      (3.3 
Depreciation and amortization    6.2      6.0      0.2   
Operating income    31.1      36.6      (5.5 
             
Interest expense, net    (6.5    (7.0    0.5   
Other expense (income), net    —      —      —   
Income tax (expense)    (9.3    (10.3    1.0   
Income (loss) from continuing operations    15.2      19.3      (4.1 
                         
    Three Months Ended March 31, 
Operating Statistics:    2012    2011 
         
Total gas sales - Dth    19,689,525      24,987,870 
 Total transport volumes - Dth                         18,050,184      16,286,552 
           

First Quarter 2012 Compared to First Quarter 2011

Gross margin decreased primarily due to a $7.2 million impact from milder weather than in the same period in the prior year. Heating degree days were 24 percent lower for the three months ended March 31, 2012 compared to the same period in the prior year and 19 percent lower than normal.

Operations and maintenance decreased primarily due to decreased bad debt costs and cost efficiencies.

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

Income tax: The effective tax rate increased as a result of an unfavorable state income tax true-up adjustment and lower pre-tax net income. The net effect of such adjustment is a non-recurring item. For the period ended March 31, 2011, the effective tax rate was favorably impacted as a result of federal income tax related research and development credits and a flow-through tax adjustment involving Iowa Gas.

Non-Regulated Energy Group

Income from continuing operations from the Non-regulated Energy group for the three months ended March 31, 2012, was $7.9 million, compared to a loss from continuing operations of $0.8 million for the same period in 2011.

Power Generation

    Three Months Ended     
    March 31,    Variance 
    2012    2011    2012 vs. 2011 
    (in millions) 
Revenue    19.6      7.6      12.0   
             
Operations and maintenance    7.1      4.2      2.9   
Depreciation and amortization    1.1      1.1      —   
Operating income    11.4      2.4      9.0   
             
Interest expense, net    (4.7    (1.8    (2.9 
Other (income) expense, net    —      1.2      (1.2 
Income tax benefit (expense)    0.3      (0.6    0.9   
Income (loss) from continuing operations    6.9      1.2      5.7   
                         
    Three Months Ended March 31, 
    2012    2011 
Operating Statistics:         
 Contracted fleet power plant availability -                 
Coal-fired plants    100.0    100.0 
Gas-fired plants    99.6    100.0 
Total availability    99.7    100.0 
             

First Quarter 2012 Compared to First Quarter 2011

Revenue increased due to the sale of capacity and energy to Colorado Electric upon commencement of commercial operation of our 200 megawatts generating facility in Pueblo, Colo.

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

Depreciation and amortization was consistent with 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 the decrease in capitalized interest as a result of the completion of construction of our generating facility in Pueblo, Colo.

Other (income) expense, net in 2011 included earnings from our partnership investment in certain Idaho generating facilities and a gain on sale of our ownership interest in the partnership which did not reoccur in 2012.

Income tax: The effective tax rate was impacted by a favorable state tax true-up that included certain tax credits. Such credits are the result of meeting certain applicable state requirements including the ability to use these incentives. The incentives pertain to qualified plant expenditures related to investment and research and development.

Coal Mining

    Three Months Ended     
    March 31,    Variance 
    2012    2011    2012 vs. 2011 
    (in millions) 
Revenue    15.0      15.5      (0.5 
             
Operations and maintenance    11.5      14.6      (3.1 
Depreciation, depletion and amortization    3.7      4.6      (0.9 
Operating income (loss)    (0.2    (3.7    3.5   
             
Interest income, net    0.8      1.0      (0.2 
Other income (expense)    0.9      0.6      0.3   
Income tax benefit (expense)    (0.5    0.9      (1.4 
Income (loss) from continuing operations    1.0      (1.3    2.3   
                         
    Three Months Ended March 31, 
    2012    2011 
Operating Statistics:    (in thousands) 
Tons of coal sold    1,103      1,370 
         
 Cubic yards of overburden moved                     2,642      3,455 
           

First Quarter 2012 Compared to First Quarter 2011

Revenue decreased primarily due to a 19 percent decrease in tons sold mainly due to the expiration of our train-load out contract and a planned outage at the Wygen II facility, partially offset by a 20 percent increase in average price per ton and increased volumes sold to the Wyodak plant that experienced an outage in 2011. The higher average sales price reflects the impact of price escalators and expiration of our train load-out contract. Approximately 50 percent of our coal production was sold under contracts that include price adjustments based on actual mining cost increases.

Operations and maintenance decreased primarily from lower costs related to a train-load out contract that expired at the end of 2011, reducing tons mined.

Depreciation, depletion and amortization decreased primarily due to lower asset base.

Income tax: The change in the effective tax rate was primarily due to the impact of percentage depletion.

Oil and Gas

    Three Months Ended     
    March 31,    Variance 
    2012    2011    2012 vs. 2011 
    (in millions) 
Revenue    21.6      17.9      3.7   
             
Operations and maintenance    10.8      10.6      0.2   
Depreciation, depletion and amortization    9.3      7.3      2.0   
Operating income    1.5      —      1.5   
             
Interest expense, net    (1.6    (1.4    (0.2 
Other (income) expense    —      (0.2    0.2   
Income tax benefit (expense), net    0.1      0.8      (0.7 
Income (loss) from continuing operations    —      (0.7    0.7   
                         
          Percentage 
    Three Months Ended March 31,    Increase 
Operating Statistics:    2012    2011    (Decrease) 
Bbls of crude oil sold      145,477      103,550    40 
Mcf of natural gas sold      2,388,475      2,011,167    19 
Gallons of NGL sold      814,585      864,440    (6  )% 
Mcf equivalent sales      3,377,706      2,755,958    23 
                 
 Depletion expense/Mcfe                              $  2.47     $  2.36   
                   
    Three Months Ended March 31, 2012    Three Months Ended March 31, 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    77.99       $  3.61      0.95      66.83      4.65      0.92 
                         
Average well-head price    83.89      1.70          84.71      2.64       
                                         

First Quarter 2012 Compared to First Quarter 2011

Revenue increased primarily due to a 17 percent increase in the average hedged price received for crude oil sales along with a 40 percent increase in crude oil volume sold. Crude oil production increases reflect activities from new wells in the company’s ongoing drilling program in the Bakken shale formation. A 17 percent increase in natural gas and NGL volumes, due primarily to the completion of three Mancos formation test wells in the San Juan and Piceance Basins, was offset by a 22 percent decrease in average hedged price for natural gas.

Depreciation, depletion and amortization increased primarily due to a higher depletion rate per Mcfe on higher volumes. The increasing depletion rate is primarily driven by a higher cost per Mcfe of our Bakken oil drilling program.

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

Corporate

First Quarter 2012 Compared to First Quarter 2011

Income from continuing operations for the three months ended March 31, 2012 was $3.4 million compared to income from continuing operations of $0.5 million for the same period in the prior year. Results for the first quarter of 2012 reflect a $12.0 million non-cash unrealized mark-to-market gain related to certain interest rate swaps compared to the first quarter of 2011, which included a $5.5 million non-cash unrealized mark-to-market gain related to these same interest rate swaps. Corporate also includes after-tax costs of $1.6 million and $0.5 million for the three months ended March 31, 2012 and 2011, respectively, which were originally allocated to our Energy Marketing segment and could not be reclassified to discontinued operations in accordance with GAAP.

Discontinued Operations

First Quarter 2012 Compared to First Quarter 2011

On Feb. 29, 2012, the company sold 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 that are expected to be settled during the second quarter of 2012. The company recorded an after-tax loss on sale of $1.6 million. 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.

Loss from discontinued operations, net of tax for the three months ended March 31, 2012 was $5.5 million, including a loss on the sale, net of tax of $1.6 million for Enserco, compared to a loss from discontinued operations, net of tax of $2.2 million for the same period in the prior year. The loss on sale includes transaction related costs, net of tax of $2.2 million.

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