Black Hills Corp. Reports Third Quarter Results, Narrows 2011 Earnings Guidance and Provides Initial 2012 Guidance

CONTINUED IMPROVEMENT IN UTILITY EARNINGS AND $329 MILLION OF GROWTH PROJECTS ADVANCING

Nov 03, 2011, 18:12 ET from Black Hills Corp.

RAPID CITY, S.D., Nov. 3, 2011 /PRNewswire/ -- Black Hills Corp. (NYSE: BKH) today announced third quarter 2011 financial results. Net income, as adjusted, was $14.4 million, or $0.37 per share, compared to $14.8 million, or $0.38 per share, for the same period in 2010 (this is a non-GAAP measure, and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided). On a GAAP basis, the company reported a net loss of $10.5 million, or $0.27 per share, for third quarter 2011, compared to net income of $12.4 million, or $0.32 per share, for the same period in 2010.

For the nine months ended Sept. 30, 2011, net income, as adjusted, was $50.5 million, or $1.27 per share, compared to $54.1 million, or $1.39 per share, for the same period in 2010 (this is a non-GAAP measure, and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided). On a GAAP basis, the company reported net income of $24.1 million, or $0.61 per share, for the nine months ended Sept. 30, 2011, compared to net income of $35.2 million, or $0.90 per share, for the same period in 2010.

"Our electric and gas utilities continued to perform well in the third quarter, reflecting a reasonable return for shareholders on the substantial utility investments made during the past several years for the benefit of our customers," said David R. Emery, chairman, president and chief executive officer of Black Hills Corp. "Our utility and IPP generation construction projects in Pueblo, Colo., with estimated total capital expenditures of $487 million, are undergoing plant commissioning, including first fires and synchronization of turbines, and remain on schedule to begin serving our southern Colorado customers on Jan. 1, 2012."

"In addition, we advanced two other key growth initiatives during the quarter.  On Nov. 1, Cheyenne Light, Fuel & Power and Black Hills Power filed for approval of a new jointly owned, $237 million, 132 megawatt generation facility that replaces a previous request by Cheyenne Light for a $158 million, 120 megawatt facility. With this recent filing, we have now announced $329 million of new utility growth projects during 2011. Our Mancos shale gas drilling program also progressed with encouraging production results from the San Juan Basin test well. The remaining two test wells in the Piceance Basin should be fracture stimulated and production tested by year-end," Emery continued.

"Two important financings were recently completed, strengthening our balance sheet and providing additional liquidity. On Nov. 1, we settled our equity forward transaction for approximately $120 million in net cash proceeds, and on Sept. 30, we renewed a $100 million, unsecured term loan for two years.

"I appreciate the tremendous amount of commitment our employees demonstrate to our customers and the significant number of major projects currently in progress. Successful completion of these key initiatives will position us to deliver the earnings growth our investors expect in 2012 and beyond."

Black Hills Corp. highlights for third quarter 2011, recent regulatory filings and other events include:

  • Construction of Colorado Electric's 180 megawatt power plant and Colorado IPP's 200 megawatt power plant in Pueblo, Colo., is on schedule and within budget. Commissioning of the two plants is ongoing with first fires achieved on all units and synchronization with the transmission grid complete for six of eight generators. The two plants will begin commercial operations Jan. 1, 2012.
  • On April 28, 2011, Colorado Electric filed a rate request with the Colorado Public Utilities Commission seeking a $40.2 million, or an 18.8 percent, increase in annual revenue, with proposed new rates effective Jan. 1, 2012. Colorado Electric filed rebuttal testimony on Oct. 14 and a joint stipulation agreement on behalf of some intervenors and the utility was submitted to the Commission on Oct. 27. Commission hearings regarding the rate case began Nov. 1.
  • On March 14, 2011, Colorado Electric filed a request for a certificate of public convenience and necessity with the Colorado Public Utilities Commission to construct a third utility-owned, 88 megawatt natural gas-fired turbine at the existing Pueblo generation location for an estimated $102 million. An initial settlement with intervenors was reached on Oct. 3 and a settlement hearing occurred on Oct. 25. Under the proposed settlement, Colorado Electric will own 42 megawatts of the 88 megawatt turbine and will sell the remaining 46 megawatts to a buyer who will provide the utility a seven-year capacity purchase agreement. The agreement also requires Colorado Electric to purchase the 46 megawatt ownership when the contract expires.
  • The Colorado Public Utilities Commission issued a decision on Aug. 12, 2011 approving Colorado Electric's request to construct and rate base 50 percent ownership in a 29 megawatt wind turbine project located south of Pueblo, Colo. The decision included the authorization to conduct a competitive solicitation for ownership of the other 50 percent of the project. The project will require a net capital investment by the utility of $27 million and is expected to be operational no later than Dec. 31, 2012.
  • On Nov. 1, 2011, Cheyenne Light filed a motion to rescind its filing for a certificate of public convenience and necessity with the Wyoming Public Service Commission to construct and operate a $158 million, 120 megawatt electric generation facility. This original filing was replaced with a new joint request filed on Nov. 1 by Cheyenne Light and Black Hills Power with the Wyoming Public Service Commission for a certificate of public convenience and necessity to construct and operate a new $237 million natural gas-fired electric generation facility and related gas and electric transmission in Cheyenne, Wyo. The proposed facility will include construction of one simple-cycle, 37 megawatt combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 megawatt unit that will be jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Light will own 40 megawatts and Black Hills Power will own 55 megawatts of the combined cycle unit.
  • The Mancos horizontal test drilling program in the San Juan and Piceance Basins continued to advance. All three test wells have been drilled, cased and cemented. The San Juan Basin well has also been fracture stimulated and placed on production with initial flow rates of approximately 6.2 million cubic feet per day. The other two wells should be fracture stimulated and production tested by year-end.
  • On Nov. 1, 2011 the equity forward agreements with J. P. Morgan were settled by issuing 4,413,519 shares of Black Hills Corporation common stock in return for approximately $120 million in net cash proceeds. The proceeds were used to pay down the corporate revolver.
  • The $100 million, one-year, unsecured term loan originally executed Dec. 15, 2010, with a cost of borrowing of 137.5 basis points over LIBOR, was extended on the same terms for two years effective Sept. 30, 2011.

BLACK HILLS CORPORATION

 CONSOLIDATED FINANCIAL RESULTS

(unaudited)

(Minor differences may result due to rounding)

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

(in millions)

2011

2010

2011

2010

Net income (loss):

Utilities:

Electric (a)

$

15.8

$

18.5

$

34.7

$

35.6

Gas

0.6

(0.6)

24.3

18.0

Total Utilities Group (b)

16.4

17.9

58.9

53.6

Non-regulated Energy:

Power generation

0.3

0.6

2.1

1.2

Coal mining

0.6

1.7

(1.1)

6.1

Oil and gas (c)

0.2

0.8

(0.6)

3.4

Energy marketing

0.4

1.5

1.5

5.2

Total Non-regulated Energy Group

1.6

4.5

1.9

15.9

Corporate (d)

(28.4)

(10.1)

(36.6)

(34.2)

GAAP Net income (loss)

$

(10.5)

$

12.4

$

24.1

$

35.2

(a)

Three and nine months ended Sept. 30, 2011 includes a $0.5 million after-tax gain on sale of assets to a related party which is eliminated in consolidation.

(b)

Three and nine months ended Sept. 30, 2010 includes $4.1 million after-tax gain on sale of a 23% ownership interest in the Wygen III power generation facility.   Nine months ended Sept. 30, 2010 also includes $1.7 million after-tax gain on sale of operating assets at Nebraska Gas.

(c)

Three and nine months ended Sept. 30, 2010 includes a $0.4 million reduction of income taxes as a result of a re-measurement of a previously reported uncertain tax position due to a settlement with the IRS.

(d)

Includes $24.9 million and $26.4 million net non-cash after-tax mark-to-market unrealized loss for the three and nine months ended Sept. 30, 2011 and $8.9 million and $27.1 million net non-cash after-tax mark-to-market unrealized loss for the three and nine months ended Sept 30, 2010, respectively.  These unrealized losses are related to certain de-designated interest rate swaps.  The three and nine months ended Sept. 30, 2011 also includes the elimination in consolidation of $0.5 million after-tax gain on sale of assets from a related party.  Additionally, the three and nine months ended Sept. 30, 2011 includes a $2.0 million reduction of income taxes as a result of a re-measurement of a previously reported uncertain tax position due to a settlement with the IRS.

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

2011

2010

2011

2010

Operating Revenue (a)  (in millions):

Utilities

$

226.4

$

214.0

$

844.4

$

829.3

Non-regulated Energy

52.0

50.5

150.2

151.3

Corporate and Intercompany eliminations

(21.9)

(14.9)

(61.6)

(48.3)

$

256.5

$

249.5

$

932.9

$

932.3

Weighted average common shares outstanding (in thousands):

Basic

39,145

38,933

39,105

38,895

Diluted

39,145

39,133

39,792

39,052

Earnings (loss) per share:

Basic

$

(0.27)

$

0.32

$

0.62

$

0.90

Diluted

$

(0.27)

$

0.32

$

0.61

$

0.90

(a)

Operating revenue for the three and nine months ended Sept 30, 2010 has been restated to eliminate intercompany transactions with our rate regulated operations; these transactions were previously not eliminated.  There was no impact on total gross margin or net income.

UPDATED 2011 EARNINGS GUIDANCE Black Hills Corp. is narrowing its 2011 net income, as adjusted, guidance from a range of $1.70 to $1.95 per share to $1.70 to $1.85 per share, based on four primary assumptions:

  • Normal weather and operations within our utility service territories during the fourth quarter;
  • Slight earnings improvement in the Coal Mining business segment;
  • Oil and gas prices do not decrease significantly; and
  • Energy marketing earnings strengthen in fourth quarter with total 2011 net income exceeding 2010.

INITIAL 2012 EARNINGS GUIDANCE Black Hills expects 2012 net income, as adjusted, to be in the range of $2.15 to $2.40 per share based on the following primary assumptions:

  • Capital spending of $420 million to $440 million, including oil and gas capital expenditures of $95 million to $100 million;
  • Financings as necessary to maintain appropriate capital structure;
  • Exclusion of the impact of the mark-to-market changes for the $250 million of dedesignated interest rate swaps;
  • Normal operations and weather conditions within our utility service territories;
  • Successful completion of rate cases for the electric and gas utilities;
  • No significant unplanned outages at any of our power generation facilities;
  • Energy Marketing earnings more than double compared to 2011 forecasted earnings;
  • Continued improvement in Coal Mining with positive full year results;
  • Total oil and natural gas production in the range of 12.3 Bcfe to 13.0 Bcfe;
  • Oil and gas annual average NYMEX prices of $4.50 per MMBtu for natural gas and $87.65 per Bbl for oil; production-weighted average well-head prices of $3.41 per Mcf and $80.65 per Bbl of oil and average hedged prices received of $3.86 per Mcf and $79.01 per Bbl; and
  • No additional significant acquisitions or divestitures.

USE OF NON-GAAP FINANCIAL MEASURES 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. 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. Net income (loss), as adjusted has limitations as an analytical tool and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our presentation of net income (loss), as adjusted 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)

2011

2010

2011

2010

(after-tax)

Income

EPS

Income

EPS

Income

EPS

Income

EPS

Net income (loss) (GAAP)

$

(10.5)

$

(0.27)

$

12.4

$

0.32

$

24.1

$

0.61

$

35.2

$

0.90

Adjustments:

Unrealized (gain) loss on interest rate swaps

24.9

0.63

8.9

0.23

26.4

0.66

27.1

0.70

Gain on sale of Elkhorn, NE assets

(1.7)

(0.04)

Gain on partial sale of Wygen III

(4.1)

(0.10)

(4.1)

(0.10)

Improved effective tax rate

(2.4)

(0.06)

(2.4)

(0.06)

Rounding

0.01

(0.01)

(0.01)

Total adjustment

24.9

0.64

2.4

0.06

26.4

0.66

18.9

0.49

Net income (loss), as adjusted (Non-GAAP)

$

14.4

$

0.37

$

14.8

$

0.38

$

50.5

$

1.27

$

54.1

$

1.39

DIVIDENDS On Oct. 27, 2011, our board of directors declared a quarterly dividend on common stock. Common shareholders of record at the close of business on Nov. 17, 2011, will receive on Dec. 1, 2011, $0.365 cents per share, equivalent to an annual dividend rate of $1.46.

CONFERENCE CALL AND WEBCAST

The company will host a live conference call and webcast at 11 a.m. EDT on Friday, Nov. 4, 2011, to discuss the company's financial and operating performance.

Those interested in listening to the live broadcast from within the United States can call 866-356-4123. International callers can call 617-597-5393. All callers need to enter the pass code 31363694 when prompted. 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 "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.

For those unable to listen to the live broadcast, a replay will be available on the company's website or by telephone through Monday, Nov. 14, 2011, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 26495135.

BUSINESS UNIT PERFORMANCE SUMMARY Business Group highlights for the three months ended Sept. 30, 2011 compared to the three months ended Sept 30, 2010 are discussed below.  The following business group and segment information does not include intercompany eliminations.  Minor differences in amounts may result due to rounding.  All amounts are presented on a pre-tax basis unless otherwise indicated.

Utilities Group - Third Quarter 2011 Net income for the Utilities Group for the three months ended Sept. 30, 2011 was $16.4 million, compared to $17.9 million in 2010.

Electric Utilities

Three Months Ended Sept. 30,

Increase (Decrease)

Nine Months Ended Sept. 30,

Increase (Decrease)

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

(in millions)

Gross margin

$

80.6

$

73.4

$

7.2

$

224.6

$

204.4

$

20.2

Operations and maintenance

34.8

33.4

1.4

106.1

102.2

3.9

Gain on sale of operating assets

(0.8)

(6.2)

5.4

(0.8)

(6.2)

5.4

Depreciation and amortization

13.2

12.5

0.7

39.1

35.6

3.5

Operating income

33.4

33.7

(0.3)

80.2

72.8

7.4

Interest expense, net

(9.7)

(10.6)

0.9

(29.8)

(27.3)

(2.5)

Other income (loss)

0.2

0.4

(0.2)

0.6

2.8

(2.2)

Income tax (expense)

(8.0)

(5.0)

(3.0)

(16.4)

(12.9)

(3.5)

Net income (loss)

$

15.8

$

18.5

$

(2.7)

$

34.7

$

35.6

$

(0.9)

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

Operating Statistics:

2011

2010

2011

2010

Retail sales - MWh

1,232,679

1,189,886

3,456,841

3,417,270

Contracted wholesale sales - MWh (a)

84,346

83,013

256,558

371,736

Off-system sales - MWh (b)

395,769

455,425

1,253,385

1,367,086

1,712,794

1,728,324

4,966,784

5,156,092

Total gas sales - Cheyenne Light - Dth

368,702

361,129

3,257,335

3,426,694

Regulated power plant availability:

Coal-fired plants (c)

95.1

%

95.9

%

91.6

%

93.2

%

Other plants

98.6

%

98.5

%

95.7

%

98.5

%

Total availability

96.4

%

96.8

%

93.1

%

95.1

%

(a)

Decrease in MWh sold during the nine months ended Sept. 30, 2011 reflects the termination of wholesale contracts when a previous wholesale power customer purchased an ownership interest in the Wygen III facility.

(b)

Includes 48,643 MWh and 222,091 MWh sold at Colorado Electric for the three and nine months ended Sept. 30, 2011, respectively.  Pursuant to a rate case order with the Colorado PUC, the margins associated with these sales have been deferred until settlement of a sharing mechanism is finalized.

(c)

Availability for the nine months ended Sept. 30, 2011 was impacted by planned major overhauls and an extended outage at the PacifiCorp-operated Wyodak plant.   Availability for the same period in 2010 was impacted by unplanned maintenance at the same plant.

Gross margin increased primarily due to $2.5 million from rate adjustments that include a return on significant capital investments, $1.7 million from an increase in retail volumes, $2.0 million from transmission cost adjustments and $0.6 million from the impact of a new Environmental Improvement Cost Recovery rider which went into effect on June 1, 2011, partially offset by lower off-system sales margins of $0.3 million.

Operations and maintenance increased primarily due to increased allocation of corporate costs resulting from higher asset deployment at the Electric Utilities and the impact of a decrease in property taxes in 2010 due to the settlement of appeals that resulted in an adjustment for prior years of $0.4 million.

Gain on sale of operating assets in 2011 represents the sale of assets to a related party and was eliminated in consolidation.  The gain on sale in 2010 represents the sale of a 23 percent ownership interest in the Wygen III generating facility to the City of Gillette, Wyoming.  

Depreciation and amortization increased primarily due to a higher asset base.

Interest expense, net decreased primarily due to higher AFUDC-borrowed associated with recent capital investments at Colorado Electric.

Income tax expense:  The effective tax rate increased from the same period in the prior year primarily due to a $2.2 million prior year tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit resulting from a rate case settlement in 2010.

Gas Utilities

Three Months Ended Sept. 30,

Increase (Decrease)

Nine Months Ended Sept. 30,

Increase (Decrease)

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

(in millions)

Gross margin

$

39.5

$

38.8

$

0.7

$

163.4

$

158.6

$

4.9

Operations and maintenance

28.3

27.0

1.4

91.1

93.4

(2.3)

Gain on sale of operating asset

(2.7)

2.7

Depreciation and amortization

6.1

5.7

0.4

18.0

19.5

(1.5)

Operating income

5.1

6.1

(1.0)

54.3

48.3

6.0

Interest expense, net

(6.3)

(7.0)

0.7

(19.6)

(20.0)

0.4

Other income (expense)

0.2

0.1

Income tax benefit (expense)

1.8

0.3

1.5

(10.5)

(10.3)

(0.2)

Net income (loss)

$

0.6

$

(0.6)

$

1.2

$

24.3

$

18.0

$

6.3

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

Operating statistics:

2011

2010

2011

2010

Total gas sales - Dth

5,753,975

5,507,031

39,958,801

39,224,176

Total transport volumes - Dth

14,385,819

13,655,534

44,510,873

44,238,881

Gross margin increased primarily due to increased industrial volumes prompted by increased irrigation from dryer weather conditions compared to the same period in the prior year and an increase in margins primarily from the non-regulated business activities.

Operations and maintenance increased primarily due to an increase in employee compensation and benefit costs.

Interest expense, net decreased primarily due to increased interest income on intercompany lending.

Income tax: The effective tax rate for 2011 was favorably impacted by a 2010 tax return true-up adjustment primarily related to flow-through treatment of certain property-related temporary differences.    

Non-regulated Energy Group - Third Quarter 2011 Net income for the Non-regulated Energy Group for the three months ended Sept. 30, 2011 was $1.6 million, compared to net income of $4.5 million for the same period in 2010. Business segment results were as follows:  

Power Generation

Three Months Ended Sept. 30,

Increase (Decrease)

Nine Months Ended Sept. 30,

Increase (Decrease)

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

(in millions)

Revenue

$

8.1

$

7.9

$

0.2

$

23.5

$

22.6

$

0.9

Operations and maintenance

4.6

3.7

0.9

12.9

12.3

0.6

Depreciation and amortization

1.1

1.0

3.2

3.4

(0.2)

Operating income

2.4

3.1

(0.6)

7.5

6.9

0.5

Interest expense, net

(1.8)

(2.2)

0.4

(5.5)

(6.2)

0.7

Other income (expense)

(0.3)

0.3

1.2

0.9

0.3

Income tax benefit (expense)

(0.3)

(0.2)

(1.1)

(0.4)

(0.7)

Net income (loss)

$

0.3

$

0.6

$

(0.2)

$

2.1

$

1.2

$

0.8

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

Operating Statistics:

2011

2010

2011

2010

Contracted fleet power plant availability -

Coal-fired plant

97.1

%

96.9

%

98.9

%

98.6

%

Natural gas-fired plant

100.0

%

100.0

%

100.0

%

100.0

%

Total availability

98.1

%

98.2

%

99.3

%

99.2

%

Operations and maintenance increased primarily due to higher maintenance costs at Black Hills Wyoming, higher transmission costs and additional costs incurred at Colorado IPP as construction progresses and employees prepare for operations of the facilities.

Other income (expense) decreased due to lower earnings from partnership investments than in 2010.

Income tax (expense) benefit:  The effective tax rate in 2011 increased over the prior period due to unfavorable adjustments related to true-up of research and development credits.

Coal Mining

Three Months Ended Sept. 30,

Increase (Decrease)

Nine Months Ended Sept. 30,

Increase (Decrease)

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

(in millions)

Revenue

$

17.8

$

14.3

$

3.6

$

48.9

$

43.3

$

5.6

Operations and maintenance

14.2

10.8

3.4

41.8

30.0

11.7

Depreciation, depletion and amortization

5.2

3.3

1.8

14.4

9.6

4.8

Operating income (loss)

(1.5)

0.2

(1.7)

(7.2)

3.7

(11.0)

Interest income, net

1.0

1.1

(0.1)

2.9

2.2

0.7

Other income (expense)

0.5

0.5

1.7

1.6

0.1

Income tax benefit (expense)

0.5

(0.1)

0.6

1.6

(1.4)

3.0

Net income (loss)

$

0.6

$

1.7

$

(1.1)

$

(1.1)

$

6.1

$

(7.2)

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

Operating Statistics:

2011

2010

2011

2010

(in thousands)

Tons of coal sold

1,550

1,489

4,155

4,340

Cubic yards of overburden moved

3,873

4,482

10,261

11,805

Revenue increased primarily due to a 20 percent increase in average sales price per ton and a 4 percent increase in coal volumes sold.  The higher average sales price reflects the impact of price escalators and adjustments in certain of our sales contracts. Approximately 40 percent of our coal production is sold under sales contracts that include adjustments to the sales price based on actual mining cost increases. Most of our remaining production is sold under contracts where the sales price may escalate based on published indices, which may not necessarily represent changes in actual mining costs.  

Operations and maintenance increases are reflective of longer haul distances and higher overburden stripping costs in the current phase of our mining.  Additionally, we experienced higher costs associated with drilling and blasting, equipment maintenance, clay parting removal, fuel, staffing levels for our train load-out facility and weather conditions.  As noted above, a portion of our production is sold under contracts that have price escalators based on published indices.  These escalators have not kept up with actual mining cost increases, reducing coal mine operating income, and are expected to continue to negatively impact 2011 results.  Previous periods also include the capitalization of certain costs associated with mine infrastructure, including our in-pit conveyor system that is used to transport coal to mine-mouth generation facilities.

Depreciation, depletion and amortization increased primarily due to higher depreciation on reclamation related costs and mining equipment.

Income tax benefit (expense): The effective tax rate in 2011 was favorably impacted by a true-up of percentage depletion related to the filing of the 2010 tax return.

Energy Marketing

Three Months Ended Sept. 30,

Increase (Decrease)

Nine Months Ended Sept. 30,

Increase (Decrease)

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

(in millions)

Gross margin

$

6.9

$

9.0

$

(2.0)

$

21.9

$

27.6

$

(5.8)

Operating expenses

5.7

6.3

(0.6)

18.0

17.8

0.2

Depreciation and amortization

0.2

0.1

0.4

0.4

0.1

Operating income (loss)

1.1

2.5

(1.4)

3.4

9.4

(6.0)

Interest expense, net

(0.4)

(0.4)

(0.1)

(1.1)

(1.9)

0.9

Other income (expense)

0.2

(0.2)

Income tax benefit (expense)

(0.4)

(0.7)

0.4

(1.0)

(2.8)

1.8

Net income (loss)

$

0.3

$

1.4

$

(1.1)

$

1.3

$

4.9

$

(3.6)

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

Operating Statistics:

2011

2010

2011

2010

Average daily quantities -

Natural gas physical - MMBtus

1,493,357

1,666,674

1,581,945

1,589,261

Crude oil physical - barrels

26,628

19,410

23,729

17,947

Coal - tons (a)

34,352

28,549

34,851

28,407

Power - MWHs (b)

593

262

(a)   Represents activity from the coal marketing business acquired on June 1, 2010.

              (b)   Power marketing began late in the third quarter of 2010.

Gross margin decreased primarily due to lower unrealized marketing margins of $28.2 million partially offset by increased realized margins of $26.2 million.  The decrease in unrealized margins primarily reflects lower natural gas margins, lower margins from the coal portfolio and losses from the power marketing portfolio. These decreases in unrealized marketing margins were partially offset by higher realized natural gas and crude oil marketing margins.  

Operating expenses decreased primarily due to lower compensation expense related to decreased margins, partially offset by higher compensation and benefit expenses relating to additional staff marketing new commodities and new geographic regions.

Income Tax benefit (expense): The effective tax rate increased primarily due to permanent differences related to the filing of the 2010 tax return.

Oil and Gas

Three Months Ended Sept. 30,

Increase (Decrease)

Nine Months Ended Sept. 30,

Increase (Decrease)

2011

2010

2011 vs. 2010

2011

2010

2011 vs. 2010

(in millions)

Revenue

$

19.2

$

19.4

$

(0.2)

$

55.9

$

57.8

$

(1.8)

Operations and maintenance

9.6

9.7

(0.2)

30.3

30.0

0.4

Depreciation, depletion and amortization

7.7

7.3

0.4

22.6

20.3

2.4

Operating income

1.9

2.3

(0.4)

2.9

7.5

(4.6)

Interest expense, net

(1.5)

(1.6)

0.1

(4.2)

(3.7)

(0.5)

Other income (expense)

0.1

0.1

(0.1)

0.7

(0.7)

Income tax benefit (expense)

(0.2)

(0.2)

0.8

(1.0)

1.8

Net income (loss)

$

0.2

$

0.8

$

(0.6)

$

(0.6)

$

3.4

$

(4.0)

Three Months Ended Sept. 30,

Nine Months Ended Sept. 30,

Operating Statistics:

2011

2010

2011

2010

Mcf equivalent sales

2,882,837

2,884,716

8,491,582

8,406,474

Average price received:

Gas/Mcf

$

4.24

$

4.64

$

4.39

$

5.12

Oil/Bbl

$

82.76

$

80.87

$

76.25

$

81.70

Revenue was comparable to the same period in the prior year with offsetting changes of a 2 percent higher average hedged oil price received and 1 percent higher natural gas volumes, exclusive of gas liquids, partially offset by a 1 percent decrease in oil volumes and a 9 percent decrease in average hedged price received for natural gas.  Oil volumes declined primarily due to natural production declines from producing properties partially offset by production gains in our ongoing Bakken drilling program.

Depreciation, depletion and amortization increased primarily due to a higher depletion rate, resulting primarily from higher finding and development costs for our Bakken oil drilling program.

Income tax (expense) benefit: The effective tax rate in 2011 was negatively impacted primarily by the true-up of percentage depletion related to the filing of the 2010 tax return while 2010 was positively impacted by a $0.4 million re-measurement of a previously recorded uncertain tax position due to a settlement agreement with the IRS.

Corporate - Third Quarter 2011 Net loss for the three months ended Sept. 30, 2011, was $28.4 million compared to net loss of $10.1 million for the same period in 2010. Results for the third quarter of 2011 reflect a $24.9 million unrealized mark-to-market non-cash after-tax loss related to interest rate swaps no longer designated as hedges for accounting purposes compared to the third quarter of 2010, which included an $8.9 million unrealized mark-to-market non-cash after-tax loss related to these interest rate swaps.

ABOUT BLACK HILLS CORP. Black Hills Corp. – 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 762,000 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, produce natural gas, oil and coal, and market energy. Black Hills employees partner to produce results that improve life with energy.

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. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates'" "believes," "estimates," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology.  The company's 2011 and 2012 earnings guidance are examples of forward-looking statements.  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, the risk factors described in Item 1A of Part I of our 2010 Annual Report on Form 10-K and Item 1A of Part II of our Form 10-Q for the quarter ended Sept. 30, 2011 filed with the SEC, and other reports that we file with the SEC from time to time, and the following:

  • Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel, transmission and purchased power in our regulated utilities and the timing in which the new rates would go into effect;
  • Our ability to receive regulatory approval to recover in rate base our expenditures for new generation facilities or other utility infrastructure;
  • Our ability to complete the construction, start up and operation of power generation facilities in a cost-effective and timely manner;
  • Our ability to generate significant earnings improvements in 2012 and beyond;
  • The accounting treatment and earnings impact associated with interest rate swaps and other derivatives;
  • Capital market conditions and market uncertainties related to interest rates, which may affect our ability to raise capital on favorable terms;
  • The timing, volatility and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates or foreign exchange rates and the demand for our services, any of which can affect our earnings, financial liquidity and the underlying value of our assets, including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and oil reserves;
  • The timing and extent of scheduled and unscheduled outages of our power generating facilities;
  • Our ability to provide accurate estimates of proved oil and gas reserves and future production and associated costs;
  • Forecasted capital expenditures associated with our oil and gas segment are driven, in part, by current market prices. Changes in crude and natural gas prices may cause us to change our planned capital expenditures related to our oil and gas operations;
  • The extent of our success in connecting natural gas supplies to gathering, processing and pipeline systems;
  • Changes in or compliance with laws and regulations, particularly those related to financial reform legislation, taxation, power generation, safety, protection of the environment, energy marketing and hydraulic fracturing;
  • Weather and other natural phenomena;
  • The effect of accounting policies issued periodically by accounting standard-setting agencies;
  • Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidation and changes in competition and (ii) general economic and political conditions, including tax rates or policies and inflation rates; and
  • Other factors discussed from time to time in our filings with the SEC.

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

Consolidating Income Statement

Three Months Ended Sept. 30, 2011

Electric Utilities

Gas Utilities

Power Generation

Coal Mining

Energy Marketing

Oil and Gas

Corporate

Intercompany Eliminations

Total

(in millions)

Operating revenue

$

153.7

$

72.7

$

8.1

$

17.8

$

6.9

$

19.2

$

46.2

$

(68.1)

$

256.5

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

6.9

19.2

46.2

(48.0)

170.3

Operations and maintenance

34.8

28.3

4.6

14.2

5.7

9.6

40.3

(42.0)

95.5

Gain on sale of operating asset

(0.8)

0.8

Depreciation, depletion and amortization

13.2

6.1

1.1

5.2

0.2

7.7

2.7

(2.7)

33.4

Operating income

33.3

5.1

2.4

(1.5)

1.1

1.9

3.1

(4.0)

41.4

Interest expense, net

(9.7)

(6.3)

(1.8)

1.0

(0.4)

(1.5)

(7.2)

3.3

(22.6)

Interest rate swaps - unrealized (loss) gain

(38.2)

(38.2)

Other income (expense)

0.2

0.5

0.1

3.0

(3.1)

0.8

Income tax benefit (expense)

(8.0)

1.8

(0.3)

0.5

(0.4)

(0.2)

14.4

0.3

8.2

Net income (loss)

$

15.8

$

0.6

$

0.3

$

0.6

$

0.3

$

0.2

$

(24.8)

$

(3.5)

$

(10.5)

Consolidating Income Statement

Nine Months Ended Sept. 30, 2011

Electric Utilities

Gas Utilities

Power Generation

Coal Mining

Energy Marketing

Oil and Gas

Corporate

Intercompany Eliminations

Total

(in millions)

Operating revenue

$

441.5

$

402.8

$

23.5

$

48.9

$

21.9

$

55.9

$

142.1

$

(203.7)

$

932.9

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

21.9

55.9

142.0

(147.8)

532.4

Operations and maintenance

106.1

91.1

12.9

41.8

18.0

30.3

123.7

(129.0)

294.9

Gain on sale of operating asset

(0.8)

0.8

Depreciation, depletion and amortization

39.1

18.0

3.2

14.4

0.4

22.6

8.0

(8.0)

97.7

Operating income

80.2

54.3

7.5

(7.2)

3.4

2.9

10.3

(11.6)

139.8

Interest expense, net

(29.8)

(19.6)

(5.5)

2.9

(1.1)

(4.2)

(22.3)

10.9

(68.7)

Interest rate swaps - unrealized (loss) gain

(40.6)

(40.6)

Other income (expense)

0.6

0.2

1.2

1.7

32.9

(32.9)

3.7

Income tax benefit (expense)

(16.4)

(10.5)

(1.1)

1.6

(1.0)

0.8

16.6

0.3

(9.7)

Net income (loss)

$

34.7

$

24.3

$

2.1

$

(1.1)

$

1.3

$

(0.6)

$

(3.2)

$

(33.3)

$

24.1

Consolidating Income Statement

Three Months Ended Sept. 30, 2010

Electric Utilities

Gas Utilities

Power Generation

Coal Mining

Energy Marketing

Oil and Gas

Corporate

Intercompany Eliminations

Total

(in millions)

Operating revenue

$

141.6

$

72.3

$

7.9

$

14.3

$

9.0

$

19.4

$

39.9

$

(54.9)

$

249.5

Fuel, purchased power and cost of gas sold

68.3

33.5

(14.8)

86.9

Gross Margin

73.4

38.8

7.9

14.3

9.0

19.4

39.9

(40.0)

162.6

Operations and maintenance

33.4

27.0

3.7

10.8

6.3

9.7

25.1

(25.2)

90.8

Gain on sale of operating assets

(6.2)

(6.2)

Depreciation, depletion and amortization

12.5

5.7

1.0

3.3

0.1

7.3

2.8

(2.8)

30.0

Operating income

33.7

6.1

3.1

0.2

2.5

2.3

12.0

(12.0)

47.9

Interest expense, net

(10.6)

(7.0)

(2.2)

1.1

(0.4)

(1.6)

(5.4)

1.9

(24.1)

Interest rate swaps - unrealized (loss) gain

(13.7)

(13.7)

Other income (expense)

0.4

(0.3)

0.5

0.1

0.8

Income tax benefit (expense)

(5.0)

0.3

(0.1)

(0.7)

7.1

1.5

Net income (loss)

$

18.5

$

(0.6)

$

0.6

$

1.7

$

1.4

$

0.8

$

0.1

$

(10.1)

$

12.4

Consolidating Income Statement

Nine Months Ended Sept. 30, 2010

Electric Utilities

Gas Utilities

Power Generation

Coal Mining

Energy Marketing

Oil and Gas

Corporate

Intercompany Eliminations

Total

(in millions)

Operating revenue

$

426.7

$

402.6

$

22.6

$

43.3

$

27.6

$

57.8

$

92.5

$

(140.8)

$

932.3

Fuel, purchased power and cost of gas sold

222.3

244.1

(45.6)

420.7

Gross Margin

204.4

158.6

22.6

43.3

27.6

57.8

92.5

(95.1)

511.6

Operations and maintenance

102.2

93.4

12.3

30.0

17.8

30.0

74.9

(77.3)

283.3

Gain on sale of operating assets

(6.2)

(2.7)

(8.9)

Depreciation, depletion and amortization

35.6

19.5

3.4

9.6

0.4

20.3

6.3

(6.3)

88.7

Operating income

72.9

48.3

6.9

3.7

9.4

7.5

11.2

(11.6)

148.5

Interest expense, net

(27.3)

(20.0)

(6.2)

2.2

(1.9)

(3.7)

(12.8)

1.6

(68.1)

Interest rate swaps - unrealized (loss) gain

(41.7)

(41.7)

Other income (expense)

2.8

0.9

1.6

0.2

0.7

18.1

(17.9)

6.4

Income tax benefit (expense)

(12.9)

(10.3)

(0.4)

(1.4)

(2.8)

(1.0)

19.0

(9.9)

Net income (loss)

$

35.6

$

18.0

$

1.2

$

6.1

$

4.9

$

3.4

$

(6.2)

$

(27.8)

$

35.2

SOURCE Black Hills Corp.



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http://www.blackhillscorp.com