BLACK HILLS CORP /SD/ - FORM 8-K - EX-99 - EXHIBIT 99 - February 2, 2015

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8-K - 8-K - BLACK HILLS CORP /SD/a8-kearningsrelease122014.htm

Black Hills Corp. Reports 18 Percent Increase in 2014 Adjusted Earnings Per Share

RAPID CITY, S.D. — Feb. 2, 2015 — Black Hills Corp. (NYSE: BKH) today announced 2014 fourth quarter and full year financial results. Adjusted income from continuing operations, a non-GAAP measure,* for the fourth quarter of 2014 was $34 million, or $0.76 per share, compared to $31 million, or $0.70 per share, for the same period in 2013. For the 12 months ending Dec. 31, 2014, adjusted income from continuing operations was $129 million, or $2.89 per share, compared to $109 million, or $2.45 per share, for the same period in 2013.

“We are pleased with another year of strong earnings growth and operational performance, benefiting both our shareholders and our customers,” said David R. Emery, chairman, chief executive officer and president of Black Hills Corp. “The company delivered adjusted earnings of $2.89 per share, up 18 percent compared to the prior year, and toward the upper end of our revised guidance range.

“This marks the fifth consecutive year of solid earnings growth for the company. Earnings were driven by excellent results in our utilities and coal mine, good performance at our power generation segment and significantly lower interest expense. The recent announcement of our 45th consecutive annual dividend increase reinforces our commitment to share earnings growth with shareholders, while also retaining sufficient capital to support long-term growth opportunities.

“Strong electric utility results were driven by contributions from our new Cheyenne Prairie Generating Station and a 15 percent increase in industrial megawatt-hour sales. Gas utility results benefited from colder than normal weather in the first quarter that added approximately $0.08 per share positive earnings impact for the year. Gas utility results also benefited from a four percent increase in distribution and transportation volumes.”
 
Three Months Ended Dec. 31,
Twelve Months Ended Dec. 31,
(in millions, except per share amounts)
2014
2013
2014
2013
Non-GAAP:*
 
 
 
 
Income from continuing operations, as adjusted
$
34.0

$
31.0

$
128.8

$
108.7

Income (loss) from discontinued operations
—

(0.9
)
—

(0.9
)
Net income, as adjusted (Non-GAAP)
$
34.0

$
30.1

$
128.8

$
107.8

 
 
 
 
 
Earnings per share from continuing operations, as adjusted, diluted
$
0.76

$
0.70

$
2.89

$
2.45

Earnings per share, discontinued operations
—

(0.02
)
—

(0.02
)
Earnings per share, as adjusted (Non-GAAP)
$
0.76

$
0.68

$
2.89

$
2.43

 
 
 
 
 
GAAP:
 
 
 
 
Income from continuing operations
$
34.0

$
19.0

$
128.8

$
115.8

Income (loss) from discontinued operations
—

(0.9
)
—

(0.9
)
Net income
$
34.0

$
18.1

$
128.8

$
115.0

 
 
 
 
 
Earnings per share from continuing operations, diluted
$
0.76

$
0.43

$
2.89

$
2.61

Income (loss) from discontinued operations
—

(0.02
)
—

(0.02
)
Earnings per share, diluted
$
0.76

$
0.41

$
2.89

$
2.59

 
 
 
 
 
* An accompanying schedule for the GAAP to Non-GAAP adjustment reconciliation is provided below.



1


“Our coal mine reported excellent financial results for the year, with a $4.1 million earnings increase year-over-year. Results reflected strong operational performance and higher contract prices on the Wyodak and Wygen I power plant coal contracts. Our power generation segment benefited from higher contract prices and excellent plant availabilities,” continued Emery.

“Our oil and gas subsidiary advanced its strategy for the Mancos Shale program during the year, but financial results, drilling progress and production lagged our expectations. The declining energy price environment affected our financial results, and we expect low prices to continue throughout 2015. We are continuing our Mancos Shale activities for 2015 and still expect approximately 12 Mancos Shale wells to be completed and tested by year-end.

“Due to recent weakness in energy prices, we are changing our outlook for natural gas and crude oil prices for 2015. We are decreasing our oil and gas price assumptions and lowering our 2015 earnings guidance range to $2.80 to $3.00 per share, compared to our previously issued guidance range of $2.90 to $3.10 per share.

“We remain excited about our future earnings growth potential. We have attractive investment opportunities in our utilities, including the new combustion turbine in Colorado and the potential of a cost of service gas program. We are encouraged by our Mancos Shale program as the capital costs to drill and complete the wells continues to decline. Focusing on organic growth, the customer experience, operational excellence and being a great workplace, we will continue our history of creating long-term shareholder value for years to come,” concluded Emery.

Black Hills Corp. highlights for the fourth quarter and full year 2014, recent regulatory filings, updates and other events include:

Utilities

•
On Dec. 19, Colorado Electric received approval from the Colorado Public Utilities Commission to increase annual revenue by an estimated $3.1 million, effective Jan. 1, 2015. Colorado Electric previously received approval from the commission to construct a 40 megawatt, natural gas-fired combustion turbine. The commission also authorized the implementation of a rider for a return on capital expenditures associated with constructing the combustion turbine.

•
On Dec. 16, Kansas Gas received approval from the Kansas Corporation Commission to increase annual base revenue by an estimated $5.2 million, effective Jan. 1, 2015.

•
On Oct. 1, Black Hills Power and Cheyenne Light, Fuel & Power placed into commercial service the jointly-owned Cheyenne Prairie Generating Station.

◦
On Oct. 1, Black Hills Power and Cheyenne Light closed the sale of $160 million of first mortgage bonds in a private placement to provide permanent financing for the plant.
◦
On Aug. 21, Black Hills Power received approval from the Wyoming Public Service Commission to increase annual electric revenues by approximately $2.2 million, effective Oct. 1, 2014. The new rates apply to electric service for the utility's 2,700 customers in Wyoming.
◦
On July 31, Cheyenne Light received approval from the Wyoming Public Service Commission to increase annual electric revenues by approximately $8.4 million and natural gas revenues by approximately $0.8 million, effective Oct. 1, 2014.
◦
On March 21, Black Hills Power filed a rate request with the South Dakota Public Utilities Commission to increase its annual electric revenue by $14.6 million. Interim rates were implemented on Oct. 1. Hearings were held Jan. 27-28, 2015, and the commission’s final decision is expected in the first quarter.

•
On July 22, Black Hills Power filed for a certificate of public convenience and necessity with the Wyoming Public Service Commission to construct a new 144-mile, $54 million electric transmission line from northeastern Wyoming to Rapid City, South Dakota. Approval for the CPCN is anticipated in the second quarter of 2015. Black Hills Power has received approval from the South Dakota Public Utilities Commission for a permit to construct the line.

•
On July 21, Cheyenne Light recorded a new all-time peak load of 198 megawatts, exceeding the previous peak load of 192 megawatts set in December 2013.

•
On May 5, Colorado Electric issued an all-source generation request, including up to 60 megawatts of eligible renewable energy resources to serve its customers in southern Colorado. Our power generation segment submitted solar and wind bids in response to the request. On December 23, the independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of the bids. The report’s results indicate that our standalone bids were not

2


among the highest ranked bids. The highest ranked bids may still provide capital investment opportunities for the company. Commission deliberations are currently scheduled for February 11 and a final decision is expected by the end of February.

•
On April 25, Cheyenne Light received approval from the Federal Energy Regulatory Commission to establish rates for transmission services under its Open Access Transmission Tariff, effective May 3, 2014. The approval includes a return on equity of 10.6 percent and a capital structure of 54 percent equity and 46 percent debt.

•
On March 21, Black Hills Power retired the Ben French, Neil Simpson I and Osage coal-fired power plants. These three plants, totaling 81 megawatts, were closed because of federal environmental regulations. These plants were partially replaced by Black Hills Power's share of the Cheyenne Prairie Generating Station.

•
We continue to acquire small natural gas distribution systems near our existing utility service territories.
◦
On Jan. 1, 2015, we closed a $6 million transaction to acquire the natural gas utility assets of MGTC, Inc., a northeast Wyoming system serving more than 400 customers. This system will be operated by and consolidated into the results of Cheyenne Light.
◦
On Oct. 14, Black Hills Corp. entered into an agreement to acquire a natural gas utility with 6,700 customers in northwest Wyoming and nearby pipeline assets for $17 million, subject to customary closing adjustments. An expedited approval process has been requested, with an expected closing in the second quarter.
◦
On April 1, we purchased a small natural gas system in Kansas adding approximately 70 new customers.

Non-Regulated Energy

•
On Sept. 3, power generation closed the sale of its 40 megawatt natural gas-fired combustion turbine to the City of Gillette, Wyoming, for approximately $22 million. The transaction includes a 20-year agreement for Black Hills Wyoming to operate the plant and share in savings when market power purchases cost less than operating the generating unit.

•
Coal mine completed negotiations for the coal price reopener related to Wyodak power plant contract. The new coal price of $18.25 per ton, an increase of approximately $4.75 per ton, was effective July 1.

•
Oil and gas drilled and completed three horizontal wells in the Mancos Shale formation in the southern Piceance Basin. The wells are expected to be placed on production in February. Drilling operations are ongoing for three additional Mancos wells. These wells are expected to be placed on production in the second quarter of 2015.

Corporate

•
On Jan. 28, 2015, the Black Hills Corp. board of directors approved an increase in the quarterly dividend of $0.015 per common share to $0.405 per share, equivalent to an annual increase of $0.06 and dividend rate of $1.62 per share. This represents the 45th consecutive annual dividend increase. Common shareholders of record at the close of Feb. 13, 2015, will receive $0.405 per share, payable on March 1, 2015.

•
On May 29, Black Hills amended and extended its $500 million, unsecured revolving credit facility at improved pricing for a five-year term expiring May 29, 2019.

•
During 2014, two credit agencies raised their corporate credit ratings for Black Hills. On Jan. 30, 2014, Moody’s Investors Service raised the company’s corporate rating to Baa1 from Baa2, with a stable outlook. On June 13, 2014, Fitch Ratings upgraded the company's corporate credit rating to BBB+ from BBB, with a stable outlook.

•
The company recently announced that Anthony Cleberg, executive vice president and chief financial officer, will retire at the end of March 2015. Richard Kinzley, previously vice president and controller and a 15-year veteran of the company, was appointed senior vice president and chief financial officer, effective Jan. 1, 2015. In addition, the senior leadership team was expanded when Brian Iverson, previously vice president and treasurer and 11-year veteran of the company, was appointed senior vice president regulatory and government affairs and assistant general counsel.

•
The company announced two new corporate officers to fill the positions vacated upon the promotions of Kinzley and Iverson. Esther Newbrough, previously assistant corporate controller, was appointed vice president - corporate controller, and Kimberly Nooney, previously assistant treasurer, was appointed vice president - treasurer.

3


BLACK HILLS CORPORATION
CONSOLIDATED FINANCIAL RESULTS

(Minor differences may result due to rounding.)

(in millions, except per share amounts)
Three Months Ended Dec. 31,
 
Twelve Months Ended Dec. 31,
 
2014
2013
 
2014
2013
Net income (loss):
 
 
 
 
 
Utilities:
 
 
 
 
 
Electric
$
15.4

$
14.1

 
$
59.6

$
52.1

Gas
13.6

12.5

 
41.9

32.7

Total Utilities Group
29.0

26.6

 
101.5

84.8

 
 
 
 
 
 
Non-regulated Energy:
 
 
 
 
 
Power generation (a)
5.4

(1.1
)
 
28.5

16.3

Coal mining
3.3

1.1

 
10.5

6.3

Oil and gas
(3.8
)
(0.5
)
 
(10.6
)
(4.2
)
Total Non-regulated Energy Group
4.9

(0.5
)
 
28.3

18.4

 
 
 
 
 
 
Corporate and Eliminations (b) (c)
0.1

(7.1
)
 
(1.0
)
12.6

 
 
 
 
 
 
Income from continuing operations
34.0

19.0

 
128.8

115.8

 
 
 
 
 
 
Income (loss) from discontinued operations, net of tax
—

(0.9
)
 
—

(0.9
)
Net income
$
34.0

$
18.1

 
$
128.8

$
114.9

 
 
 
 
 
 
Weighted average common shares outstanding - Diluted
44.6

44.5

 
44.6

44.4

 
 
 
 
 
 
Diluted -
 
 
 
 
 
Continuing Operations
$
0.76

$
0.43

 
$
2.89

$
2.61

Discontinued Operations
—

(0.02
)
 
—

(0.02
)
Total Diluted Earnings Per Share
$
0.76

$
0.41

 
$
2.89

$
2.59


(a)
Power Generation results for the three and 12 months ended Dec. 31, 2013, include an after-tax expense of $6.6 million for the early settlement of interest rate swaps in conjunction with the early repayment of the Black Hills Wyoming Project Financing debt and the write-off of deferred financing costs.
(b)
Corporate results for the three and 12 months ended Dec. 31, 2013, include a non-cash after-tax gain related to mark-to-market adjustment on certain interest rate swaps of $0.5 million and $20 million, respectively.
(c)
Corporate results for the 12 months ended Dec. 31, 2013, include $7.6 million after-tax expense for a make-whole premium, write-off of deferred financing costs for early redemption of our $250 million notes and interest expense on new debt.

4


EARNINGS GUIDANCE REVISED

Black Hills now expects its 2015 earnings, as adjusted, to be in the range of $2.80 to $3.00 per share versus the $2.90 to $3.10 per share range most recently issued on Nov. 3, 2014. The revised guidance range reflects the earnings impact of low natural gas and crude oil prices.

The revised guidance range is based upon updates to our capital expenditures forecast and oil and gas assumptions, including production volumes and energy prices. The rest of our original assumptions have not changed. The revised guidance is based upon the following key assumptions:

•
Capital spending of $457 million, including oil and gas capital expenditures of $123 million;
•
Normal operations and weather conditions within our utility service territories that impact customer usage, and planned construction, maintenance and/or capital investment projects;
•
Successful completion of rate cases for electric and gas utilities;
•
No significant unplanned outages at any of our power generation facilities;
•
Oil and natural gas production in the range of 12.5 to 14.0 billion cubic feet equivalent;
•
Oil and natural gas annual average NYMEX prices of $3.00 per million British thermal units for natural gas and $50.00 per barrel for oil; production-weighted average well-head prices of $1.56 per MMBtu for natural gas and $45.00 per bbl of oil, and average hedged prices received of $2.08 per MMBtu and $56.78 per bbl;
•
Oil and natural gas depletion expense in the range of $2.35 to $2.55 per million cubic feet equivalent;
•
Excludes any non-cash ceiling test impairment charges we may be required to take if natural gas and crude oil prices remain at low levels for an extended period of time;
•
No equity financing in 2015 except for approximately $3 million from the dividend reinvestment program; and
•
No significant acquisitions or divestitures.

CONFERENCE CALL AND WEBCAST

The company will host a live conference call and webcast at 11 a.m. EST on Tuesday, Feb. 3, 2015, 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 “Events & Presentations” in the “Investor Relations” section. The presentation will be posted on the website before the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. Those interested in asking a question during the live broadcast or those without internet access can call 866-953-6860 if calling within the United States. International callers can call 617-399-3484. All callers need to enter the pass code 53421889 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 Tuesday, Feb. 24, 2015, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 37427119.

USE OF NON-GAAP FINANCIAL MEASURE

As noted in this news release, in addition to presenting its earnings information in conformity with Generally Accepted Accounting Principles (GAAP), the company has provided non-GAAP earnings data reflecting adjustments for special items as specified in the GAAP to Non-GAAP adjustment reconciliation table below. Income (loss) from continuing operations, as adjusted, and Net income (loss), as adjusted, is defined as Income (loss) from continuing operations and Net income (loss), adjusted for expenses and gains that the company believes do not reflect the company’s core operating performance. The company believes that non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. The company’s management uses these non-GAAP financial measures as an indicator for planning and forecasting future periods. These non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. The presentation of these Non-GAAP financial measures should not be construed as an inference that future results will not be affected by unusual, non-routine, or non-recurring items.


5


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

GAAP TO NON-GAAP ADJUSTMENT RECONCILIATION

 
Three Months Ended Dec. 31,
 
Twelve Months Ended Dec. 31,
(In millions, except per share amounts)
2014
 
2013
 
2014
 
2013
(after-tax)
Income
 
EPS
 
Income
 
EPS
 
Income
 
EPS
 
Income
 
EPS
Income (loss) from continuing operations (GAAP)
$
34.0

 
$
0.76

 
$
19.0

 
$
0.43

 
$
128.8

 
$
2.89

 
$
115.8

 
$
2.61

Adjustments, after-tax:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrealized (gain) loss on certain interest rate swaps
—

 
—

 
(0.5
)
 
(0.01
)
 
—

 
—

 
(19.6
)
 
(0.44
)
Costs associated with payment of Black Hills Wyoming Project Debt Settlement including settlement of interest rate swaps and write-off of deferred financing cost, net of interest savings
—

 
—

 
6.6

 
0.15

 
—

 
—

 
6.6

 
0.15

Financing costs relating to repayment of $250 million bonds, net of interest savings (a)
—

 
—

 
5.9

 
0.13

 
—

 
—

 
5.9

 
0.13

Total adjustments
—

 
—

 
12.0

 
0.27

 
—

 
—

 
(7.1
)
 
(0.16
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations, as adjusted (Non-GAAP)
34.0

 
0.76

 
31.0

 
0.70

 
128.8

 
2.89

 
108.7

 
2.45

Income (loss) from discontinued operations, net of tax
—

 
—

 
(0.9
)
 
(0.02
)
 
—

 
—

 
(0.9
)
 
(0.02
)
Net income (loss) (Non-GAAP)
$
34.0


$
0.76

 
$
30.1

 
$
0.68

 
$
128.8

 
$
2.89

 
$
107.8

 
$
2.43


(a)
Financing costs include a make-whole premium, write-off of deferred financing costs and interest expense on the new debt.

BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months and 12 months ended Dec. 31, 2014, compared to the three months and 12 months ended Dec. 31, 2013, are discussed below. The following business group and segment information does not include certain inter-company 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 was revised to reclassify information related to discontinued operations.


6


Utilities Group

Income from continuing operations for the Utilities Group for the three months ended Dec. 31, 2014, was $29 million, compared to $27 million for the same period in 2013 while income from continuing operations for the 12 months ended Dec. 31, 2014, was $101 million, compared to $85 million in 2013.

Electric Utilities

 
Three Months Ended Dec. 31,
Increase (Decrease)
 
Twelve Months Ended Dec. 31,
Increase (Decrease)
 
2014
2013
2014 vs. 2013
 
2014
2013
2014 vs. 2013
 
(in millions)
Gross margin
$
101.9

$
93.6

$
8.3

 
$
382.7

$
371.3

$
11.4

 
 
 
 
 
 
 
 
Operations and maintenance
43.7

40.6

3.1

 
165.6

160.0

5.6

Depreciation and amortization
21.4

19.5

1.9

 
79.4

77.7

1.7

Operating income
36.8

33.5

3.3

 
137.7

133.6

4.1

 
 
 
 
 
 
 
 
Interest expense, net
(13.2
)
(14.0
)
0.8

 
(48.8
)
(56.3
)
7.5

Other (expense) income, net
0.2

0.2

—

 
1.2

0.6

0.6

Income tax benefit (expense)
(8.3
)
(5.6
)
(2.7
)
 
(30.5
)
(25.8
)
(4.7
)
Income (loss) from continuing operations
$
15.4

$
14.1

$
1.3

 
$
59.6

$
52.1

$
7.5


 
Three Months Ended Dec. 31,
 
Twelve Months Ended Dec. 31,
Operating Statistics:
2014
2013
 
2014
2013
Retail sales - MWh
1,212,592

1,172,249

 
4,775,808

4,642,254

Contracted wholesale sales - MWh
89,930

88,664

 
340,871

357,193

Off-system sales - MWh 
284,808

366,422

 
1,118,641

1,456,762

Total electric sales - MWh
1,587,330

1,627,335

 
6,235,320

6,456,209

 
 
 
 
 
 
Total gas sales - Cheyenne Light - Dth
1,435,290

1,813,603

 
4,537,995

5,034,357

 
 
 
 
 
 
Regulated power plant availability:
 
 
 
 
 
Coal-fired plants (a)
98.1
%
96.4
%
 
93.8
%
96.7
%
Other plants (b)
93.0
%
96.1
%
 
90.2
%
96.5
%
Total availability
94.8
%
96.3
%
 
91.5
%
96.6
%

(a)
The 12 months ended Dec. 31, 2014 reflect a planned overhaul on Neil Simpson II for emissions controls upgrades.
(b)
The 12 months ended Dec. 31, 2014 reflect planned overhauls for control system upgrades to meet NERC cyber security regulations on the Ben French CT's 1-4.


7

Fourth Quarter 2014 Compared to Fourth Quarter 2013

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $6.0 million. Higher retail megawatt hours sold added an increase of $0.8 million, and facility improvements at one of our large industrial customers drove a $1.2 million increase in technical service revenues. These partially offset a decrease from the TCA of $0.4 million.

Operations and maintenance increased primarily due to higher employee costs, and a true-up made in the prior year for generation dispatch services billed to a third party.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of Cheyenne Prairie.

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.

Income tax: The effective tax rate increased in 2014 primarily due to a current year unfavorable true-up adjustment, and a decrease in flow-through tax adjustments.

Full Year 2014 Compared to Full Year 2013

Gross margin increased primarily due to a return on additional investments which increased base electric margins by $9.0 million, and increased rider margins from Cheyenne Prairie by $5.5 million. Industrial megawatt hours sold increased by approximately 15 percent, primarily due to load growth at Cheyenne Light resulting in increased margins of $1.7 million. Facility improvements at one of our large industrial customers drove a $1.8 million increase in technical service revenues. These increases are partially offset by a $3.5 million decrease from lower demand and residential megawatt hours sold driven by a 29 percent decrease in cooling degree days compared to the same period in the prior year, a $1.6 million decrease from the TCA, and a $0.8 million decrease from a construction savings incentive recognized in the prior year. Our Cheyenne Light gas utility experienced a decrease in heating degree days, resulting in a $1.4 million decrease in retail natural gas sales.

Operations and maintenance increased primarily due to property taxes, regulatory support and legal fees, generation maintenance, and employee costs.

Depreciation and amortization increased primarily due to a higher asset base driven by the addition of Cheyenne Prairie.

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013, and extending our revolving credit facility under favorable terms during the second quarter of 2014.

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



8

Gas Utilities

 
Three Months Ended Dec. 31,
Increase (Decrease)
 
Twelve Months Ended Dec. 31,
Increase (Decrease)
 
2014
2013
2014 vs. 2013
 
2014
2013
2014 vs. 2013
 
(in millions)
Gross margin
$
63.3

$
64.2

$
(0.9
)
 
$
236.9

$
229.2

$
7.7

 
 
 
 
 
 
 
 
Operations and maintenance
32.2

30.5

1.7

 
132.6

126.1

6.5

Depreciation and amortization
6.8

6.7

0.1

 
26.5

26.4

0.1

Operating income
24.3

27.0

(2.7
)
 
77.8

76.8

1.0

 
 
 
 
 
 
 
 
Interest expense, net
(3.9
)
(6.1
)
2.2

 
(15.3
)
(24.3
)
9.0

Other (expense) income, net
—

(0.1
)
0.1

 
—

(0.1
)
0.1

Income tax (expense)
(6.8
)
(8.3
)
1.5

 
(20.7
)
(19.7
)
(1.0
)
Income (loss) from continuing operations
$
13.6

$
12.5

$
1.1

 
$
41.9

$
32.7

$
9.2


 
Three Months Ended Dec. 31,
 
Twelve Months Ended Dec. 31,
Operating Statistics:
2014
2013
 
2014
2013
Total gas sales - Dth
17,429,853

18,895,858

 
60,323,416

59,097,493

Total transport volumes - Dth
17,077,837

16,406,006

 
67,463,143

63,821,546


Fourth Quarter 2014 Compared to Fourth Quarter 2013

Gross margin decreased primarily due to a decrease in heating degree days compared to the same period in the prior year, contributing to lower retail volumes sold. Heating degree days were 13 percent lower for the three months ended Dec. 31, 2014, compared to the same period in the prior year, and 3 percent lower than normal. This decrease was partially offset by favorable transport margins, and rider margins on integrity capital investments.

Operations and maintenance increased primarily due to an increase in employee costs and property taxes.

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.

Income tax: The effective tax rate for the fourth quarter of 2014 decreased primarily as a result of favorable state tax adjustment.

Full Year 2014 Compared to Full Year 2013

Gross margin increased primarily due to higher transport volumes which increased transport margins by $1.7 million. Rider margins increased $2.9 million primarily due to additional capital investments, and $1.6 million of additional margin was attributed to year over year customer growth. Higher retail volumes sold, driven mostly by a 7 percent increase in heating degree days realized in the first quarter of 2014 resulted in a $1.2 million increase. Heating degree days for the twelve months ended Dec. 31, 2014, were 3 percent lower than the same period in the prior year, and 6 percent higher than normal.

Operations and maintenance increased primarily due to employee costs, property taxes, outside services, and uncollectible accounts attributed to increased revenue.

Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.


9

Income tax: The effective tax rate for 2014 was lower primarily due to a favorable true-up adjustment to the filed 2013 income tax return, in addition to an increase in flow-through tax adjustments.

Non-Regulated Energy Group

Income from continuing operations from the Non-regulated Energy group for the three months ended Dec. 31, 2014, was $4.9 million, compared to loss from continuing operations of $0.5 million for the same period in 2013. Income from continuing operations from the Non-regulated Energy group for the 12 months ended Dec. 31, 2014, was $28 million compared to $18 million for the same period in 2013.

Power Generation

 
Three Months Ended Dec. 31,
Increase (Decrease)
 
Twelve Months Ended Dec. 31,
Increase (Decrease)
 
2014
2013
2014 vs. 2013
 
2014
2013
2014 vs. 2013
 
(in millions)
Revenue
$
21.2

$
20.6

$
0.6

 
$
87.6

$
83.0

$
4.6

 
 
 
 
 
 
 
 
Operations and maintenance
9.4

7.9

1.5

 
33.1

30.2

2.9

Depreciation and amortization
1.1

1.2

(0.1
)
 
4.5

5.1

(0.6
)
Operating income
10.7

11.5

(0.8
)
 
49.9

47.8

2.1

 
 
 
 
 
 
 
 
Interest expense, net
(0.9
)
(12.2
)
11.3

 
(3.7
)
(20.4
)
16.7

Other income (expense), net
—

—

—

 
—

—

—

Income tax benefit (expense)
(4.4
)
(0.4
)
(4.0
)
 
(17.7
)
(11.1
)
(6.6
)
Income (loss) from continuing operations
$
5.4

$
(1.1
)
$
6.5

 
$
28.5

$
16.3

$
12.2


 
Three Months Ended Dec. 31,
 
Twelve Months Ended Dec. 31,
Contracted Fleet Power Plant Availability
2014
2013
 
2014
2013
Gas-fired plants  
98.8
%
99.1
%
 
99.0
%
99.0
%
Coal-fired plants (a)
84.5
%
84.0
%
 
94.7
%
94.5
%
Total availability
95.0
%
95.6
%
 
97.8
%
97.9
%
_________________________
(a)
Availability was impacted by planned outages at Wygen I occurring during the three months ended Dec. 31, 2014 and Dec. 31, 2013, respectively.


Fourth Quarter 2014 Compared to Fourth Quarter 2013

Revenue increased primarily due to an increase in megawatt hours delivered at a higher price.

Operations and maintenance increased primarily due to outage expenses on Wygen 1, and other outside services.

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

Interest expense, net decreased primarily due to refinancing higher cost project debt and settling associated interest rate swaps in the fourth quarter of 2013. The fourth quarter of 2013 included $7.7 million relating to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing and a $2.4 million write-off of related deferred financing costs.


10


Income tax: The effective tax rate increased compared to the same period in the prior year due to an unfavorable increase in valuation allowances related to state tax credits. The fourth quarter of 2013, which resulted in a pre-tax net loss, produced a tax expense due to an unfavorable true-up adjustment.

Full Year 2014 Compared to Full Year 2013

Revenue increased primarily due to an increase in megawatt hours delivered at higher prices, an increase in fired hours, and an increase from the new economy energy PPA with the City of Gillette, partially offset by the expiration of the CTII capacity contract with Cheyenne Light.

Operations and maintenance increased primarily due to increased outside services and materials, and additional maintenance costs on the Wygen I outage, partially offset by decreased employee costs.

Depreciation and amortization decreased primarily due to lower depreciation at Black Hills Wyoming. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the original cost of the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased primarily due to refinancing higher cost project debt and settling associated interest rate swaps in the fourth quarter of 2013. The fourth quarter of 2013 included $7.7 million relating to the cost to settle the interest rate swaps associated with Black Hills Wyoming’s project financing and a $2.4 million write-off of related deferred financing costs.
 
Income tax: The effective tax rate was comparable to the same period in the prior year.

Coal Mining

 
Three Months Ended Dec. 31,
Increase (Decrease)
 
Twelve Months Ended Dec. 31,
Increase (Decrease)
 
2014
2013
2014 vs. 2013
 
2014
2013
2014 vs. 2013
 
(in millions)
Revenue
$
17.6

$
13.4

$
4.2

 
$
63.4

$
56.6

$
6.8

 
 
 
 
 
 
 
 
Operations and maintenance
11.1

10.0

1.1

 
41.2

39.5

1.7

Depreciation, depletion and amortization
2.5

2.8

(0.3
)
 
10.3

11.5

(1.2
)
Operating income (loss)
4.0

0.6

3.4

 
11.9

5.6

6.3

 
 
 
 
 
 
 
 
Interest (expense) income, net
(0.1
)
(0.1
)
—

 
(0.4
)
(0.6
)
0.2

Other income (expense)
0.5

0.6

(0.1
)
 
2.3

2.3

—

Income tax benefit (expense)
(1.1
)
0.1

(1.2
)
 
(3.3
)
(0.9
)
(2.4
)
Income (loss) from continuing operations
$
3.3

$
1.1

$
2.2

 
$
10.5

$
6.3

$
4.2


 
Three Months Ended Dec. 31,
 
Twelve Months Ended Dec. 31,
 
2014
2013
 
2014
2013
Operating Statistics:
(in thousands)
Tons of coal sold
1,085

1,020

 
4,317

4,285

Cubic yards of overburden moved
1,722

518

 
4,646

3,192

 
 
 
 
 
 
Revenue per ton
$
16.26

$
13.14

 
$
14.68

$
13.21



11


Fourth Quarter 2014 Compared to Fourth Quarter 2013

Revenue increased primarily due to a 24 percent increase in price per ton sold, and 6 percent increase in tons sold. Pricing was favorably impacted by a coal contract price increase with the third-party operator of the Wyodak plant, as well as an increase in pricing on contracts containing price adjustments based on actual mining costs. Approximately 50 percent of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes.

Operations and maintenance increased primarily due to materials and outside services related to major maintenance projects, and an increase in royalties and revenue related taxes driven by higher revenue.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets driven by a reduction in equipment run hours from changes in the mine plan design, and lower depreciation of mine reclamation costs.

Interest (expense) income, net was comparable to the same period in the prior year.

Income tax: The effective tax rate in 2014 is higher due to the reduced impact of the tax benefit of percentage depletion.

Full Year 2014 Compared to Full Year 2013

Revenue increased primarily due to an 11 percent increase in the price per ton sold driven primarily by a coal price increase with the third-party operator of the Wyodak plant. Price per ton also increased as a result of an increase in pricing on contracts containing price adjustments based on actual mining costs. Approximately 50 percent of our coal production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. Our mining costs have increased due to higher operations and maintenance costs driven by mining in areas with a higher stripping ratio than the prior year, thereby increasing our price per ton for these customers.

Operations and maintenance increased primarily due to mining in areas with higher overburden, materials and outside services on major maintenance projects, and an increase in royalties and revenue related taxes driven by increased revenue, partially offset by lower employee costs.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets driven by a reduction in equipment run hours from changes in the mine plan design, and lower depreciation of mine reclamation costs.

Interest (expense) income, net is comparable to the same period in the prior year.

Income tax: The effective tax rate in 2014 is higher due to the reduced impact of the tax benefit of percentage depletion.


12



Oil and Gas

 
Three Months Ended Dec. 31,
Increase (Decrease)
 
Twelve Months Ended Dec. 31,
Increase (Decrease)
 
2014
2013
2014 vs. 2013
 
2014
2013
2014 vs. 2013
 
(in millions)
Revenue
$
11.6

$
13.3

$
(1.7
)
 
$
55.1

$
54.9

$
0.2

 
 
 
 
 
 
 
 
Operations and maintenance
10.9

9.5

1.4

 
42.7

40.4

2.3

Depreciation, depletion and amortization
6.1

5.0

1.1

 
27.6

21.8

5.8

Operating income
(5.4
)
(1.2
)
(4.2
)
 
(15.1
)
(7.3
)
(7.8
)
 
 
 
 
 
 
 
 
Interest expense, net
(0.4
)
(0.3
)
(0.1
)
 
(1.7
)
(0.6
)
(1.1
)
Other (expense) income, net
0.1

—

0.1

 
0.2

0.1

0.1

Income tax benefit (expense), net
1.9

0.9

1.0

 
6.0

3.5

2.5

Income (loss) from continuing operations
$
(3.8
)
$
(0.5
)
$
(3.3
)
 
$
(10.6
)
$
(4.2
)
$
(6.4
)

 
Three Months Ended Dec. 31,
Percentage Increase
Twelve Months Ended Dec. 31,
Percentage Increase
Operating Statistics:
2014
2013
(Decrease)
2014
2013
(Decrease)
Bbls of crude oil sold
88,066

89,773

(2
)%
337,196

336,140

—
 %
Mcf of natural gas sold
1,698,148

1,700,143

—
 %
7,155,076

6,983,104

2
 %
Gallons of NGL sold
1,364,030

874,423

56
 %
5,651,321

3,704,639

53
 %
Mcf equivalent sales
2,421,405

2,363,699

2
 %
9,985,584

9,529,178

5
 %
 
 
 
 
 
 
 
Depletion expense/Mcfe
$
2.31

$
1.56

48
 %
$
2.21

$
1.83

21
 %
 
 
 
 
 
 
 
Average hedged price received:
 
 
 
 
 
 
Crude Oil
$
68.63

$
80.39

(15
)%
$
79.39

$
89.34

(11
)%
Natural Gas
$
2.42

$
2.63

(8
)%
$
2.91

$
2.69

8
 %

 
Dec. 31, 2014
 
Dec. 31, 2013
Oil and Gas Total Proved
Crude Oil
Natural Gas
NGLs (b)
Total
 
Crude Oil
Natural Gas
Total
Reserves: (a)
(Mbbl)
(MMcf)
(Mbbl)
(MMcfe)
 
(Mbbl)
(MMcf)
(MMcfe)
Total proved reserves
4,276

65,440

1,720

101,416

 
3,921

63,190

86,713

 
 
 
 
 
 
 
 
 
Well-head reserve prices
$
85.80

$
3.33

$
34.81

 
 
$
89.79

$
3.45

 

(a)
Oil and gas reserve information is based on reports prepared by Cawley, Gillespie & Associates, Inc. an independent consulting and engineering firm.
(b)
Proved reserves data for NGL’s for 2013 is not available.


13


Fourth Quarter 2014 Compared to Fourth Quarter 2013

Revenue decreased primarily due to a 15 percent decrease in the average hedged price received for crude oil sold and a 10 percent decrease in the average hedged price received for natural gas sold, partially offset by a 2% production increase.

Operations and maintenance increased primarily due to increased employee costs, higher lease and field operation expense, and higher production and ad valorem taxes on higher unhedged revenue.

Depreciation, depletion and amortization increased primarily due to a higher depletion rate applied to increased production.

Interest expense, net was comparable to the same period in the prior year.

Income tax benefit (expense): Each period presented reflected a tax benefit. The tax benefit for 2014 was impacted by an unfavorable true-up adjustment to the filed 2013 income tax return.

Full Year 2014 Compared to Full Year 2013

Revenue increased primarily due to a 5 percent increase in volumes sold and an 8 percent increase in average price received for natural gas sold, partially offset by an 11 percent decrease in the average price received for crude oil sold.

Operations and maintenance increased primarily due to increased employee costs, higher lease operating and field operation expense, and higher production taxes and ad valorem taxes on higher revenue.

Depreciation, depletion and amortization increased primarily due to a higher depletion rate applied to increased production.

Interest expense, net increased primarily due to third-party interest received on non-operated well revenue in the prior year that offset 2013 expense.

Income tax (expense) benefit: Each period presented reflects a tax benefit. The tax benefit for 2014 was impacted by an unfavorable true-up adjustment to the filed 2013 income tax return.

Corporate

Fourth Quarter 2014 Compared to Fourth Quarter 2013

Income from continuing operations for the three months ended Dec. 31, 2014, was $0.1 million compared to loss from continuing operations of $7.1 million for the same period in the prior year. Results for the fourth quarter of 2014 increased primarily due to the refinancing activity that took place during the fourth quarter of 2013. The fourth quarter of 2013 included a $0.8 million non-cash unrealized mark-to-market gain related to certain interest rate swaps. Corporate results for fourth quarter of 2013 also included $10 million of costs related to early retirement of $250 million senior unsecured notes including a make-whole premium, write-off of deferred financing costs and interest expense on new debt.

Full Year 2014 Compared to Full Year 2013

Loss from continuing operations for the 12 months ended Dec. 31, 2014, was $1.0 million compared to income from continuing operations of $13 million for the same period in the prior year. Results for the year ended Dec. 31, 2014, were primarily due to refinancing activity that took place during the fourth quarter of 2013. Results for the 12 months ended Dec. 31, 2013 reflect a $30 million non-cash unrealized mark-to-market gain related to certain interest rate swaps. Corporate results for 2013 also include $10 million of costs related to early retirement of $250 million senior unsecured notes including a make-whole premium, write-off of deferred financing costs and interest expense on new debt.


14


Discontinued Operations

On February 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds at date of the sale were approximately $165 million, subject to final post-closing adjustments. The proceeds represent approximately $108 million received from the buyer and approximately $58 million cash retained from Enserco before closing.

The buyer asserted certain purchase-price adjustments, some that we accepted, and several that we disputed. The disputed claims were substantially resolved in our favor through a binding arbitration decision dated Jan. 17, 2014. We expensed $1.1 million in 2013 related to the claims assigned to arbitration. Loss from discontinued operations was $0.9 million for the twelve months ended December 31, 2013, inclusive of these arbitration decision amounts.

ABOUT BLACK HILLS CORP.

Black Hills Corp. (NYSE: BKH), a growth-oriented, vertically-integrated energy company with a tradition of exemplary service and a vision to be the energy partner of choice, is based in Rapid City, South Dakota. The company serves 777,000 natural gas and electric utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company generates wholesale electricity, and produces 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.


15


CAUTION REGARDING FORWARD-LOOKING STATEMENTS

This news release includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this news release that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. This includes, without limitations, our 2015 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 2013 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 obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings in periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power and other operating costs, and the timing in which new rates would go into effect;

•
Our ability to obtain regulatory approval to include additional generation in rate base in the future, and to implement a cost of service gas program;

•
Our ability to receive regulatory approvals for announced acquisitions and to successfully close and implement the transactions;

•
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;

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

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

•
Other factors discussed from time to time in our filings with the SEC.

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

16


 
Consolidating Income Statement
Three Months Ended Dec. 31, 2014
Electric Utilities
Gas Utilities
Power Generation
Coal Mining
Oil and Gas
Corporate
Electric Utility Inter-Co Lease Elim*
Power Generation Inter-Co Lease Elim*
Other Inter-Co Eliminations
Total
 
(in millions)
Revenue
$
175.0

$
177.2

$
2.3

$
12.0

$
11.6

$
—

$
—

$
—

$
—

$
378.1

Inter-company revenue
3.8

—

18.9

5.6

—

57.9

—

0.6

(86.8
)
—

Fuel, purchased power and cost of gas sold
76.9

113.9

—

—

—

—

1.1

—

(26.6
)
165.3

Gross Margin
101.9

63.3

21.2

17.6

11.6

57.9

(1.1
)
0.6

(60.2
)
212.8

 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
43.7

32.2

9.4

11.1

10.9

55.6

—

—

(57.9
)
105.0

Depreciation, depletion and amortization
21.4

6.8

1.1

2.5

6.1

2.2

(3.3
)
3.3

(2.2
)
37.8

Operating income (loss)
36.7

24.3

10.7

4.0

(5.4
)
0.2

2.2

(2.7
)
(0.1
)
70.0

 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(14.2
)
(4.0
)
(1.1
)
(0.1
)
(0.6
)
(12.3
)
—

—

13.3

(18.9
)
Interest rate swaps - unrealized (loss) gain
—

—

—

—

—

—

—

—

—

—

Interest income
1.0

—

0.2

—

0.2

11.9

—

—

(12.9
)
0.4

Other income (expense)
0.2

—

—

0.5

0.1

18.5

—

—

(18.8
)
0.6

Income tax benefit (expense)
(8.3
)
(6.8
)
(4.4
)
(1.1
)
1.9

0.6

(0.8
)
1.0

—

(18.0
)
Income (loss) from continuing operations
$
15.4

$
13.6

$
5.4

$
3.3

$
(3.8
)
$
19.0

$
1.4

$
(1.7
)
$
(18.5
)
$
34.0

*
The generating facility constructed by Black Hills Colorado IPP at our Pueblo Airport Generation site which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expenses of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidations.




17


 
Consolidating Income Statement
Three Months Ended Dec. 31, 2013
Electric Utilities
Gas Utilities
Power Generation
Coal Mining
Oil and Gas
Corporate
Electric Utility Inter-Co Lease Elim*
Power Generation Inter-Co Lease Elim*
Other Inter-Co Eliminations
Total
 
(in millions)
Revenue
$
169.2

$
166.2

$
1.0

$
5.7

$
13.3

$
—

$
—

$
—

$
—

$
355.4

Inter-company revenue
4.0

—

19.6

7.8

—

56.0

—

0.5

(87.8
)
—

Fuel, purchased power and cost of gas sold
79.6

102.1

—

—

—

—

1.0

—

(29.4
)
153.3

Gross Margin
93.6

64.2

20.6

13.4

13.3

56.0

(1.0
)
0.5

(58.5
)
202.1

 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
40.6

30.5

7.9

10.0

9.5

52.3

—

—

(54.9
)
95.9

Depreciation, depletion and amortization
19.5

6.7

1.2

2.8

5.0

2.8

(3.3
)
3.1

(2.8
)
35.1

Operating income (loss)
33.5

26.9

11.4

0.7

(1.2
)
0.9

2.3

(2.7
)
(0.8
)
71.1

 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(15.3
)
(6.1
)
(12.3
)
(0.2
)
(0.7
)
(27.6
)
—

—

19.6

(42.5
)
Interest rate swaps - unrealized (loss) gain
—

—

—

—

—

0.8

—

—

—

0.8

Interest income
1.4

0.1

0.1

—

0.4

17.1

—

—

(18.6
)
0.4

Other income (expense)
0.2

(0.1
)
—

0.6

—

12.6

—

—

(12.9
)
0.4

Income tax benefit (expense)
(5.6
)
(8.3
)
(0.4
)
0.1

0.9

2.1

(0.9
)
1.0

—

(11.1
)
Income (loss) from continuing operations
$
14.1

$
12.5

$
(1.1
)
$
1.1

$
(0.5
)
$
5.9

$
1.5

$
(1.7
)
$
(12.8
)
$
19.0

*
The generating facility constructed by Black Hills Colorado IPP at our Pueblo Airport Generation site which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expenses of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidations.



18


 
Consolidating Income Statement
Twelve Months Ended Dec. 31, 2014
Electric Utilities
Gas Utilities
Power Generation
Coal Mining
Oil and Gas
Corporate
Electric Utility Inter-Co Lease Elim*
Power Generation Inter-Co Lease Elim*
Other Inter-Co Eliminations
Total
 
(in millions)
Revenue
$
683.2

$
617.8

$
6.4

$
31.1

$
55.1

$
—

$
—

$
—

$
—

$
1,393.6

Inter-company revenue
14.1

—

81.2

32.3

—

222.5

—

2.1

(352.1
)
—

Fuel, purchased power and cost of gas sold
314.6

380.9

—

—

—

0.1

4.1

—

(117.9
)
581.8

Gross Margin
382.7

236.9

87.6

63.4

55.1

222.3

(4.1
)
2.1

(234.2
)
811.8

 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
165.6

132.6

33.1

41.2

42.7

213.4

—

—

(225.5
)
403.2

Depreciation, depletion and amortization
79.4

26.5

4.5

10.3

27.6

7.7

(13.1
)
12.8

(7.7
)
148.1

Operating income (loss)
137.7

77.8

49.9

11.9

(15.1
)
1.2

8.9

(10.7
)
(1.0
)
260.5

 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(53.4
)
(15.7
)
(4.4
)
(0.5
)
(2.6
)
(50.3
)
—

—

55.9

(71.0
)
Interest rate swaps - unrealized (loss) gain
—

—

—

—

—

—

—

—

—

—

Interest income
4.6

0.4

0.7

0.1

0.9

49.0

—

—

(53.8
)
1.9

Other income (expense)
1.2

—

—

2.3

0.2

61.6

—

—

(62.6
)
2.7

Income tax benefit (expense)
(30.5
)
(20.7
)
(17.7
)
(3.3
)
6.0

—

(3.3
)
4.0

0.1

(65.4
)
Income (loss) from continuing operations
$
59.6

$
41.9

$
28.5

$
10.5

$
(10.6
)
$
61.5

$
5.6

$
(6.8
)
$
(61.4
)
$
128.8

*
The generating facility constructed by Black Hills Colorado IPP at our Pueblo Airport Generation site which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expenses of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidations.




19


 
Consolidating Income Statement
Twelve Months Ended Dec. 31, 2013
Electric Utilities
Gas Utilities
Power Generation
Coal Mining
Oil and Gas
Corporate
Electric Utility Inter-Co Lease Elim*
Power Generation Inter-Co Lease Elim*
Other Inter-Co Eliminations
Total
 
(in millions)
Revenue
$
651.4

$
539.7

$
4.6

$
25.2

$
54.9

$
—

$
—

$
—

$
—

$
1,275.9

Inter-company revenue
13.9

—

78.4

31.4

—

220.6

—

1.8

(346.2
)
—

Fuel, purchased power and cost of gas sold
294.0

310.5

—

—

—

0.1

3.7

—

(116.2
)
492.1

Gross Margin
371.3

229.2

83.0

56.6

54.9

220.5

(3.7
)
1.8

(230.0
)
783.7

 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
160.0

126.1

30.2

39.5

40.4

202.8

—

—

(212.0
)
386.9

Depreciation, depletion and amortization
77.7

26.4

5.1

11.5

21.8

11.6

(13.1
)
11.9

(11.6
)
141.2

Operating income (loss)
133.6

76.8

47.8

5.6

(7.3
)
6.1

9.4

(10.0
)
(6.4
)
255.6

 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(61.5
)
(25.2
)
(21.2
)
(0.6
)
(2.3
)
(85.2
)
—

—

84.3

(111.8
)
Interest rate swaps - unrealized (loss) gain
—

—

—

—

—

30.2

—

—

—

30.2

Interest income
5.3

1.0

0.8

—

1.6

69.8

—

—

(76.7
)
1.7

Other income (expense)
0.6

(0.1
)
—

2.3

0.1

41.5

—

—

(42.6
)
1.8

Income tax benefit (expense)
(25.8
)
(19.7
)
(11.1
)
(0.9
)
3.5

(7.8
)
(3.5
)
3.7

—

(61.6
)
Income (loss) from continuing operations
$
52.1

$
32.7

$
16.3

$
6.3

$
(4.2
)
$
54.5

$
5.9

$
(6.3
)
$
(41.5
)
$
115.8

*
The generating facility constructed by Black Hills Colorado IPP at our Pueblo Airport Generation site which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expenses of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidations.



Investor Relations:
Jerome E. Nichols    605-721-1171
Email    investorrelations@blackhillscorp.com

Media Contact:
24-hour Media Assistance    866-243-9002


20

BLACK HILLS CORP /SD/ Reports