BLACK HILLS CORP /SD/ - FORM 8-K - EX-99 - EXHIBIT 99 - May 4, 2015

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8-K - 8-K - BLACK HILLS CORP /SD/a8-kq12015earningsrelease.htm




Black Hills Corp. Reports First Quarter 2015 Results

RAPID CITY, S.D. — May 4, 2015 — Black Hills Corp. (NYSE: BKH) today announced first-quarter 2015 financial results. Net income was $48 million, or $1.07 per diluted share, compared to net income of $48 million, or $1.08 per diluted share, for the same period in 2014.

“Our electric utility and coal mining segments reported solid earnings growth during the quarter,” said David R. Emery, chairman, president and chief executive officer of Black Hills Corp. “The growth was largely offset by a negative impact at our utilities due to moderate weather compared to the same period last year and low commodity prices at our oil and gas business. To mitigate these negative impacts, we implemented corporate-wide cost containment efforts. Overall, financial results for the quarter were in line with the same period last year.

“We made progress on several key strategic projects in our utilities and oil and gas businesses to position the company for future earnings growth. We ordered a new 40 megawatt turbine for Colorado Electric and expect to start construction on the $65 million project mid-year. We are awaiting approval for a $54 million electric transmission line and hope to commence construction in the third quarter. Additionally, we expect to close the previously announced northwest Wyoming utility acquisition in the second quarter.

“Our oil and gas subsidiary accelerated its Mancos Shale drilling program during the quarter. Three Mancos Shale wells drilled in late 2014 were placed on production early in the year. Production results to date have exceeded our expectations. We took advantage of declining oil field service costs and rig availability to contract two additional drilling rigs. We now have three drilling rigs operating and ten additional Mancos Shale horizontal wells in progress.”
 
Three Months Ended March 31,
(in millions, except per share amounts)
2015
2014
GAAP:
 
 
Net income
$
47.9

$
48.1

 
 
 
Earnings per share, diluted
$
1.07

$
1.08


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

Utilities

•
Construction of a new $65 million, 40 megawatt, natural gas-fired turbine at Colorado Electric’s Pueblo Airport Generating Station is moving forward. We expect to commence construction mid-year with the turbine in service by the end of 2016.

•
On March 2, 2015, Black Hills Power received an order from the South Dakota Public Utilities Commission approving an increase in annual electric revenues of approximately $6.9 million.

•
On Oct. 14, 2014, Black Hills Corp. entered into an agreement to acquire a natural gas utility with 6,700 customers in northwest Wyoming and certain nearby pipeline assets for $17 million, subject to customary closing adjustments. The transaction requires approval by the Wyoming Public Service Commission, the Montana Public Service Commission and the Federal Energy Regulatory Commission. The transaction is expected to close by the end of the second quarter of 2015.

•
On July 22, 2014, 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. We are awaiting approval of the CPCN from the Wyoming commission. Black Hills Power received approval on Nov. 6, 2014, from the South Dakota Public Utilities Commission for a permit to construct this line. Assuming timely receipt of remaining approvals, we plan to commence construction in the third quarter of 2015.




•
On May 5, 2014, 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. An independent evaluator submitted a report to the Colorado Public Utilities Commission confirming the ranking of all bids. On February 27, the commission determined that none of the renewable bids were cost effective. The commission reaffirmed that decision on April 16 in response to a request for reconsideration. In their written order, the commission noted precedent allowing utilities to secure new bid pricing. Colorado Electric, at its discretion, has 60 days to renegotiate bids and submit a revised contract or contracts for approval. We are reviewing our options.

Non-regulated Energy

•
Three horizontal Mancos Shale gas wells were drilled and completed in late 2014 and early 2015 and placed on production in the first quarter. Production results to date have exceeded expectations.

•
Two additional drilling rigs were recently contracted for the Mancos Shale drilling program. Drilling operations are ongoing for 10 additional horizontal wells on three separate surface pads in the southern Piceance Basin.

•
Oil and gas financial results were negatively impacted by lower crude oil and natural gas prices, which decreased 26 percent and 34 percent, respectively, compared to the first quarter of 2014.

Corporate

•
On April 27, 2015, Black Hills’ board of directors declared a quarterly dividend on the common stock. Shareholders of record at the close of business on May 18, 2015, will receive $0.405 per share, equivalent to an annual dividend rate of $1.62 per share, payable on June 1, 2015.

•
On April 13, 2015, Black Hills closed a new $300 million unsecured term loan. The loan has a maturity date of April 12, 2017, with a cost of borrowing based on LIBOR plus a spread of 90 basis points. The proceeds of the term loan were used to repay a $275 million term loan due June 19, 2015, and for other corporate purposes.

2



BLACK HILLS CORPORATION
CONSOLIDATED FINANCIAL RESULTS

(Minor differences may result due to rounding.)

 
Three Months Ended March 31,
 
2015
2014
 
(in millions)
Net income (loss):
 
 
Utilities:
 
 
Electric
$
18.9

$
14.6

Gas
22.2

24.7

Total Utilities Group
41.1

39.3

 
 
 
Non-regulated Energy:
 
 
Power generation
8.1

8.1

Coal mining
3.0

2.4

Oil and gas
(5.1
)
(2.0
)
Total Non-regulated Energy Group
6.0

8.5

 
 
 
Corporate and Eliminations
0.7

0.3

 
 
 
Net income (loss)
$
47.9

$
48.1




 
Three Months Ended March 31,
 
2015
2014
Weighted average common shares outstanding (in thousands):
 
 
Basic
44,541

44,330

Diluted
44,660

44,554

 
 
 
Earnings per share:
 
 
Basic -
 
 
Total Basic Earnings Per Share
$
1.08

$
1.09

 
 
 
Diluted -
 
 
Total Diluted Earnings Per Share
$
1.07

$
1.08



3



2015 EARNINGS GUIDANCE REAFFIRMED

Black Hills reaffirms its guidance for 2015 earnings, as adjusted, to be in the range of $2.80 to $3.00 per share as most recently issued on Feb. 2, 2015.

CONFERENCE CALL AND WEBCAST

Black Hills will host a live conference call and webcast at 11 a.m. EDT on Tuesday, May 5, 2015, to discuss our financial and operating performance.

To access the live webcast and download a copy of the investor presentation, go to the Black Hills website at www.blackhillscorp.com, and click on “Events and Presentations” in the “Investor Relations” section. The presentation will be posted on the website before the webcast. Listeners should allow at least five minutes for registering and accessing the presentation. Those interested in asking a question during the live broadcast or those without Internet access can call 855-638-5678 if calling within the United States. International callers can call 724-498-4407. All callers need to enter the pass code 23448553 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, May 26, 2015, at 855-859-2056 in the United States and at 404-537-3406 for international callers. The replay pass code is 23448553.

USE OF NON-GAAP FINANCIAL MEASURE

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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


4


BUSINESS UNIT PERFORMANCE SUMMARY

Business Group highlights for the three months ended March 31, 2015, compared to the three months ended March 31, 2014, are discussed below. The following business group and segment information does not include certain intercompany eliminations. Minor differences in comparative amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated.

Utilities Group

Net income (loss) for the Utilities Group for the first quarter ended March 31, 2015, was $41 million, compared to $39 million in 2014.

Electric Utilities
 
Three Months Ended March 31,
Variance
 
2015
2014
2015 vs. 2014
 
(in millions)
Gross margin
$
108.6

$
95.4

$
13.2

 
 
 
 
Operations and maintenance
44.0

42.6

1.4

Depreciation and amortization
21.0

19.1

1.9

Operating income
43.6

33.7

9.9

 
 
 
 
Interest expense, net
(13.8
)
(12.0
)
(1.8
)
Other (income) expense, net
0.1

0.3

(0.2
)
Income tax benefit (expense)
(10.9
)
(7.4
)
(3.5
)
Net income (loss)
$
18.9

$
14.6

$
4.3


 
Three Months Ended March 31,
 
2015
2014
Operating Statistics:
 
 
Retail sales - MWh
1,242,363

1,183,195

Contracted wholesale sales - MWh
84,271

95,228

Off-system sales - MWh 
296,979

337,898

Total electric sales - MWh
1,623,613

1,616,321

 
 
 
Total gas sales - Cheyenne Light - Dth
1,912,273

1,855,498

 
 
 
Regulated power plant availability:
 
 
Coal-fired plants
91.3
%
95.5
%
Other plants (a)
95.7
%
78.1
%
Total availability
94.1
%
86.6
%

(a)
The three months ended March 31, 2014, reflects an unplanned outage due to a turbine bearing replacement and combustor upgrade at Pueblo Airport Generation Station.


5


First Quarter 2015 Compared with First Quarter 2014

Gross margin increased primarily due to a return on additional investment in our generating facilities which increased electric gross margins by $9.4 million compared to the same period in the prior year. Electric margins were favorably impacted by higher retail load and demand that increased megawatt hours sold driving an increase of $2.5 million. Colorado Electric also received approval of a one-time settlement agreement from the CPUC on our renewable energy standard adjustment related to Busch Ranch, which increased margins by $2.1 million. Partially offsetting these increases was a negative weather impact on electric and gas residential retail margins of $3.2 million driven by a 14 percent decrease in heating degree days compared to the same period in the prior year.

Operations and maintenance increased primarily due to costs related to Cheyenne Prairie, which was placed into commercial service on Oct. 1, 2014, and an increase in allowance for uncollectible account expense.

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

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

Income tax benefit (expense): The effective tax rate is higher in 2015 primarily due to the increase in liability with respect to uncertain tax positions related to research and development credits.

Gas Utilities
 
Three Months Ended March 31,
Variance
 
2015
2014
2015 vs. 2014
 
(in millions)
Gross margin
$
81.5

$
84.8

$
(3.3
)
 
 
 
 
Operations and maintenance
35.4

35.4

—

Depreciation and amortization
7.0

6.5

0.5

Operating income
39.0

42.9

(3.9
)
 
 
 
 
Interest expense, net
(3.8
)
(3.9
)
0.1

Other expense (income), net
—

—

—

Income tax benefit (expense)
(12.9
)
(14.4
)
1.5

Net income (loss)
$
22.2

$
24.7

$
(2.5
)

 
Three Months Ended March 31,
 
2015
2014
Operating Statistics:
 
 
Total gas sales - Dth
25,466,960

29,150,704

Total transport volumes - Dth
19,815,225

21,278,066


First Quarter 2015 Compared with First Quarter 2014

Gross margin decreased primarily due to a $5.3 million impact from milder weather than in the same period in the prior year. Heating degree days were 9 percent lower for the three months ended March 31, 2015, compared to the same period in the prior year and 4 percent higher than normal in the current year, compared to 14 percent higher than normal in the prior year. Partially offsetting this weather impact was a $1.2 million increase from base rate adjustments at Kansas Gas which were effective January 1, 2015, and a $0.6 million increase from year-over-year customer growth.


6


Operations and maintenance was comparable to the prior year reflecting increases in property taxes and allowance for uncollectible account expense, offset by a decrease in employee costs.

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

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

Non-Regulated Energy Group

Net income (loss) from the Non-regulated Energy group for the three months ended March 31, 2015, was $6.0 million, compared to Net income (loss) of $8.5 million for the same period in 2014.

Power Generation
 
Three Months Ended March 31,
Variance
 
2015
2014
2015 vs. 2014
 
(in millions)
Revenue
$
22.7

$
22.3

$
0.4

 
 
 
 
Operations and maintenance
7.8

7.7

0.1

Depreciation and amortization
1.1

1.2

(0.1
)
Operating income
13.7

13.5

0.2

 
 
 
 
Interest expense, net
(0.9
)
(0.9
)
—

Other (income) expense, net
—

—

—

Income tax benefit (expense)
(4.7
)
(4.5
)
(0.2
)
Net income (loss)
$
8.1

$
8.1

$
—


 
Three Months Ended March 31,
 
2015
2014
Operating Statistics:
 
 
Contracted fleet power plant availability -
 
 
Coal-fired plants
98.2
%
99.3
%
Gas-fired plants
98.9
%
97.9
%
Total availability
98.7
%
98.2
%

First Quarter 2015 Compared with First Quarter 2014

Revenue was comparable to the prior year reflecting an increase in PPA pricing, offset by the net effect of the expiration of the CTII PPA and subsequent economy energy PPA.

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

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

Income tax benefit (expense): The effective tax rate is higher in 2015 primarily due to the increase in liability with respect to uncertain tax positions related to research and development credits.


7



Coal Mining
 
Three Months Ended March 31,
Variance
 
2015
2014
2015 vs. 2014
 
(in millions)
Revenue
$
15.9

$
15.5

$
0.4

 
 
 
 
Operations and maintenance
9.9

10.1

(0.2
)
Depreciation, depletion and amortization
2.5

2.7

(0.2
)
Operating income (loss)
3.5

2.7

0.8

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

Other income (expense), net
0.6

0.6

—

Income tax benefit (expense)
(1.0
)
(0.7
)
(0.3
)
Net income (loss)
$
3.0

$
2.5

$
0.5


 
Three Months Ended March 31,
 
2015
2014
Operating Statistics:
(in thousands)
Tons of coal sold
1,019

1,087

Cubic yards of overburden moved
1,413

910

 
 
 
Revenue per ton
$
15.64

$
14.26


First Quarter 2015 Compared with First Quarter 2014

Revenue increased primarily due to a 10 percent increase in price per ton sold, partially offset by a 6 percent decrease in tons sold. The increase in pricing was driven by the price re-opener on our coal contract with the third-party operator of the Wyodak plant which became effective in the third quarter of 2014, partially offset by contract price adjustments based on actual mining costs. Tons of coal sold was negatively impacted by unplanned customer outages, and the closure of Neil Simpson 1 in March 2014. 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 decreased primarily due to mining efficiencies resulting in reduced major maintenance, blasting and lower fuel costs, partially offset by a higher overburden stripping ratio and a favorable coal tax adjustment recognized in 2014.

Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets driven by a lower net asset base.

Income tax benefit (expense): The effective tax rate in 2015 is higher due primarily to the reduced impact of the tax benefit of percentage depletion.



8



Oil and Gas
 
Three Months Ended March 31,
Variance
 
2015
2014
2015 vs. 2014
 
(in millions)
Revenue
$
11.3

$
14.9

$
(3.6
)
 
 
 
 
Operations and maintenance
10.9

11.1

(0.2
)
Depreciation, depletion and amortization
8.1

6.6

1.5

Operating income
(7.7
)
(2.9
)
(4.8
)
 
 
 
 
Interest income (expense), net
(0.4
)
(0.5
)
0.1

Other (income) expense, net
(0.2
)
—

(0.2
)
Income tax benefit (expense)
3.3

1.3

2.0

Net income (loss)
$
(5.1
)
$
(2.0
)
$
(3.1
)

 
Three Months Ended March 31,
Percentage Increase
 
2015
2014
(Decrease)
Operating Statistics:
 
 
 
Bbls of crude oil sold
80,730

74,262

9
 %
Mcf of natural gas sold
2,254,042

1,759,964

28
 %
Bbls of NGL sold
28,770

27,041

6
 %
Mcf equivalent sales
2,911,043

2,367,782

23
 %
 
 
 
 
Depletion expense/Mcfe
$
2.40

$
2.25

7
 %
 
 
 
 
Average hedged price received (a) (b)
 
 
 
Crude Oil (Bbl)
$
66.86

$
90.75

(26
)%
Natural Gas (MMcf)
$
2.20

$
3.35

(34
)%
Natural Gas Liquids (Bbl)
$
13.74

$
49.02

(72
)%
 
 
 
 
Average well-head price
 
 
 
Crude Oil (Bbl)
$
40.29

$
90.75

(56
)%
Natural Gas (MMcf)
$
1.05

$
3.22

(67
)%
__________
(a)
Net of hedge settlement gains and losses.
(b)
Based on our quarterly ceiling test, no impairment charge was necessary as of March 31, 2015. If crude oil and natural gas prices remain at or near the current low levels, a ceiling impairment charge could occur in 2015.

 
 
 
 
 
 
 
 



9


First Quarter 2015 Compared with First Quarter 2014

Revenue decreased primarily due to lower commodity market prices for both crude oil and natural gas resulting in a 26 percent decrease in the average hedged price received for crude oil sold, and a 34 percent decrease in the average hedged price received for natural gas sold. A production increase of 23 percent, driven primarily by three new Piceance Mancos Shale wells placed on production in the first quarter of 2015, partially offset the decrease in prices.

Operations and maintenance decreased primarily due to lower production taxes and ad valorem taxes on lower revenue and lower employee costs, partially offset by higher lease and field operation expenses from non-operated wells.

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

Income tax (expense) benefit: The effective tax rate in 2015 is comparable to the same period in the prior year.

Corporate Activities

First Quarter 2015 Compared with First Quarter 2014

Net income for Corporate activity was $0.7 million for the three months ended March 31, 2015, compared to net income of $0.3 million for the three months ended March 31, 2014. The variance from the prior year was primarily due to:

•
Lower interest expense, primarily driven by favorable margins on base rate borrowings on our Revolving Credit Facility for the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Our Revolving Credit Facility agreement was amended and extended on May 29, 2014 with improved margins on base rate borrowings of 0.25% compared to the agreement it replaced.

ABOUT BLACK HILLS CORP.

Black Hills Corp. (NYSE: BKH) is a growth-oriented, vertically-integrated energy company with a tradition of improving life with energy and a vision to be the energy partner of choice. Based in Rapid City, South Dakota, the company serves 785,000 natural gas and electric utility customers in Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company also generates wholesale electricity and produces natural gas, crude oil and coal. Black Hills Corp.'s more than 2,000 employees form partnerships and produce positive results for our customers, communities and shareholders. More information is available at www.blackhillscorp.com.


10



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 2014 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 obtain regulatory approval to construct a 144-mile electric transmission line;

•
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 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.


11


(Minor differences may result due to rounding.)

 
Consolidating Income Statement
Three Months Ended March 31, 2015
Electric Utilities (a)
Gas Utilities
Power Generation (a)
Coal Mining
Oil and Gas
Corporate
Electric Utility Inter-Co Lease Elim (a)
Power Generation Inter-Co Lease Elim (a)
Other Inter-Co Eliminations
Total
 
(in millions)
Revenue
$
183.0

$
237.7

$
2.0

$
8.1

$
11.3

$
—

$
—

$
—

$
—

$
442.0

Intercompany revenue
3.4

—

20.7

7.8

—

57.3

—

0.6

(89.8
)
—

Fuel, purchased power and cost of gas sold
77.8

156.2

—

—

—

—

1.1

—

(29.8
)
205.3

Gross margin
108.6

81.5

22.7

15.9

11.3

57.3

(1.1
)
0.6

(60.0
)
236.7

 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
44.0

35.4

7.8

9.9

10.9

54.8

—

—

(57.7
)
105.1

Depreciation, depletion and amortization
21.0

7.0

1.1

2.5

8.1

2.2

(3.3
)
3.0

(2.2
)
39.6

Operating income
43.6

39.0

13.7

3.5

(7.7
)
0.4

2.2

(2.5
)
(0.2
)
92.0

 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(14.8
)
(3.9
)
(1.1
)
(0.1
)
(0.5
)
(12.4
)
—

—

13.4

(19.3
)
Interest income
1.0

0.1

0.2

—

0.1

11.8

—

—

(13.0
)
0.3

Other income (expense)
0.1

—

—

0.6

(0.2
)
30.2

—

—

(30.5
)
0.1

Income tax benefit (expense)
(10.9
)
(12.9
)
(4.7
)
(1.0
)
3.3

1.0

(0.8
)
0.9

—

(25.1
)
Net income (loss)
$
18.9

$
22.2

$
8.1

$
3.0

$
(5.1
)
$
31.0

$
1.4

$
(1.6
)
$
(30.2
)
$
47.9


(a)
The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.

 
 
 
 
 
 
 
 
 
 
 

 
Consolidating Income Statement
Three Months Ended March 31, 2014
Electric Utilities (a)
Gas Utilities
Power Generation (a)
Coal Mining
Oil and Gas
Corporate
Electric Utility Inter-Co Lease Elim (a)
Power Generation Inter-Co Lease Elim (a)
Other Inter-Co Eliminations
Total
 
(in millions)
Revenue
$
178.1

$
259.3

$
1.3

$
6.6

$
14.8

$
—

$
—

$
—

$
—

$
460.1

Intercompany revenue
4.0

—

21.0

8.8

—

56.7

—

(0.5
)
(90.0
)
—

Fuel, purchased power and cost of gas sold
86.7

174.5

—

—

—

—

(1.0
)
—

(29.8
)
230.4

Gross margin
95.4

84.8

22.3

15.4

14.8

56.7

1.0

(0.5
)
(60.2
)
229.7

 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
42.6

35.4

7.6

10.0

11.1

54.3

—

—

(56.9
)
104.1

Depreciation, depletion and amortization
19.1

6.5

1.2

2.7

6.6

1.7

(1.8
)
—

—

36.0

Operating income
33.7

42.9

13.5

2.7

(2.9
)
0.7

2.8

(0.5
)
(3.3
)
89.6

 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(13.5
)
(4.1
)
(1.2
)
(0.1
)
(0.7
)
(12.8
)
—

—

14.9

(17.5
)
Interest income
1.3

0.2

0.1

—

0.3

12.5

—

—

(14.0
)
0.4

Other income (expense)
0.3

—

—

0.5

—

28.5

—

—

(28.4
)
0.9

Income tax benefit (expense)
(7.2
)
(14.3
)
(4.3
)
(0.7
)
1.3

—

(0.1
)
—

—

(25.3
)
Net income (loss)
$
14.6

$
24.7

$
8.1

$
2.4

$
(2.0
)
$
28.9

$
2.7

$
(0.5
)
$
(30.8
)
$
48.1


(a)
The generating facility owned by Black Hills Colorado IPP at our Pueblo Airport Generating Station which sells energy and capacity under a 20-year PPA to Colorado Electric is accounted for as a capital lease. Therefore, revenue and expense of the Electric Utilities and Power Generation segments reflect adjustments for lease accounting which are eliminated in consolidation.

12



 
 
 
 
 
 
 
 
 
 
 


Investor Relations:
 
Jerome E. Nichols

Phone
605-721-1171
Email
jerome.nichols@blackhillscorp.com
 
 
Media Contact:
 
24-hour Media Assistance
866-243-9002


13

BLACK HILLS CORP /SD/ Reports