BLACK HILLS CORP /SD/ - FORM 8-K - EX-99 - EARNINGS RELEASE - May 3, 2012

Attached files

file filename
8-K - BLACK HILLS CORP /SD/a8-kq12012earningsrelease.htm



BLACK HILLS CORP. REPORTS 2012 FIRST QUARTER RESULTS AND REVISES GUIDANCE

RAPID CITY, SD — May 3, 2012 — Black Hills Corp. (NYSE: BKH) today 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 (this is a non-GAAP measure and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided).

“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.


2


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.



3


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


4




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.


5


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.


CONFERENCE CALL AND WEBCAST

Black Hills Corp. will host a live conference call and webcast at 11 a.m. EDT on Friday, May 4, 2012, to discuss the company’s financial and operating performance.

To access the live webcast and download a copy of the investor presentation, go to the Black Hills website at www.blackhillscorp.com, and click on “Webcast” in the “Investor Relations” section. The presentation will be posted on the website before the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. Those interested in asking a question during the live broadcast or those without Internet access can call 800-659-2056 if calling within the United States. International callers can call 617-614-2714. All callers need to enter the pass code 68683967 when prompted.

For those unable to listen to the live broadcast, a replay will be available on the company’s website or by telephone through Friday, May 18, 2012, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 48146922.


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.



6


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.

7



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.



8


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.


9


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.


10


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


 
Three Months Ended March 31,
Percentage 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

5
 %
 

 
Three Months Ended March 31, 2012
 
Three Months Ended March 31, 2011
Average Prices
Crude Oil
Natural Gas
Natural Gas Liquids
 
 
Crude Oil
Natural Gas
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.


11


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.


ABOUT BLACK HILLS CORP.

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



12


CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This news release includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this news release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. This includes, without limitations, our 2012 earnings guidance. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 2011 Annual Report on Form 10-K filed with the SEC, and other reports that we file with the SEC from time to time, and the following:

•
The accuracy of our assumptions on which our earnings guidance is based;

•
Our ability to mitigate the impacts of the unseasonably warm winter and our expectations of sustained low natural gas prices for the remainder of 2012 through our continuous improvement program and cost-reduction efforts;

•
Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings in periodic applications to recover costs for capital additions, fuel, transmission and purchased power and the timing in which the new rates would go into effect;

•
Our ability to complete our capital program in a cost-effective and timely manner, including our ability to successfully develop our Mancos shale gas reserves located in the San Juan and Piceance Basins;

•
Our ability to implement our new mine plan and to reduce our overall mining costs; 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.


13



 
Consolidating Income Statement
Three Months Ended March 31, 2012
Electric Utilities
Gas Utilities
Power Generation
Coal Mining
Oil and Gas
Corporate
Intercompany Eliminations
Total
 
(in millions)
Revenue
$
156,133

$
180,522

$
1,178

$
6,373

$
21,645

$
—

$
—

$
365,851

Intercompany revenue
3,036

—

18,449

8,616

—

51,684

(81,785
)
—

Fuel, purchased power and cost of gas sold
73,716

111,985

—

—

—

34

(28,552
)
157,183

Gross Margin
85,453

68,537

19,627

14,989

21,645

51,650

(53,233
)
208,668

 
 
 
 
 
 
 
 
 
Operations and maintenance
39,230

31,299

7,132

11,478

10,834

47,062

(46,974
)
100,061

Gain on sale of operating asset
—

—

—

—

—

—

—

—

Depreciation, depletion and amortization
18,932

6,157

1,114

3,696

9,323

2,624

(3,287
)
38,559

Operating income
27,291

31,081

11,381

(185
)
1,488

1,964

(2,972
)
70,048

 
 
 
 
 
 
 
 
 
Interest expense, net
(16,512
)
(7,668
)
(4,972
)
—

(1,606
)
(22,967
)
24,490

(29,235
)
Interest rate swaps - unrealized (loss) gain
—

—

—

—

—

12,045

—

12,045

Interest income
3,292

1,128

229

755

1

16,302

(21,270
)
437

Other income (expense)
718

11

5

881

29

14,392

(14,343
)
1,693

Income tax benefit (expense)
(6,043
)
(9,345
)
271

(451
)
101

(4,134
)
(116
)
(19,717
)
Income (loss) from continuing operations
$
8,746

$
15,207

$
6,914

$
1,000

$
13

$
17,602

$
(14,211
)
$
35,271





14


 
Consolidating Income Statement
Three Months Ended March 31, 2011
Electric Utilities
Gas Utilities
Power Generation
Coal Mining
Oil and Gas
Corporate (a)
Intercompany Eliminations
Total
 
(in millions)
Revenue
$
144,430

$
230,266

$
687

$
7,614

$
17,906

$
—

$
—

$
400,903

Intercompany revenue
3,839

—

6,933

7,881

—

49,664

(68,385
)
(68
)
Fuel, purchased power and cost of gas sold
74,074

153,129

—

—

—

15

(16,707
)
210,511

Gross Margin
74,195

77,137

7,620

15,495

17,906

49,649

(51,678
)
190,324

 
 
 
 
 
 
 
 
 
Operations and maintenance
37,114

34,560

4,188

14,572

10,567

43,994

(44,948
)
100,047

Gain on sale of operating assets
—

—

—

—

—

—

—

—

Depreciation, depletion and amortization
12,824

6,021

1,064

4,618

7,321

2,829

(2,767
)
31,910

Operating income
24,257

36,556

2,368

(3,695
)
18

2,826

(3,963
)
58,367

 
 
 
 
 
 
 
 
 
Interest expense, net
(13,412
)
(8,368
)
(2,193
)
(2
)
(1,383
)
(22,586
)
24,538

(23,406
)
Interest rate swaps - unrealized (loss) gain
—

—

—

—

—

5,465

 
5,465

Interest income
3,468

1,396

403

962

—

14,912

(20,593
)
548

Other income (expense)
409

25

1,203

569

(185
)
22,316

(22,318
)
2,019

Income tax benefit (expense)
(4,473
)
(10,346
)
(595
)
868

835

(214
)
—

(13,925
)
Income (loss) from continuing operations
$
10,249

$
19,263

$
1,186

$
(1,298
)
$
(715
)
$
22,719

$
(22,336
)
$
29,068

________________
(a)
Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not reclassified to discontinued operations but included in the Corporate segment.

Investor Relations:
 
Jerome Nichols
605-721-1171
 
 
Media Contact:
 
Media Relations Line
866-243-9002


15

BLACK HILLS CORP /SD/ Reports