BLACK HILLS CORPORATION RAPID CITY, S.D., Nov. 3, 2014 /PRNewswire/ -- Black Hills Corp. (NYSE: BKH) today announced third-quarter 2014 financial results. Net income, as adjusted, and net income were both $27 million, or $0.60 per diluted share, compared to net income, as adjusted, of $21 million, or $0.47 per diluted share, and net income of $23 million, or $0.52 per diluted share, for the same period in 2013 (net income, as adjusted, is a non-GAAP measure, and an accompanying schedule for the GAAP to non-GAAP adjustment reconciliation is provided).
"We are pleased with our improved financial performance and strong operational execution across our business segments," said David R. Emery, chairman, president and chief executive officer of Black Hills Corp. "Adjusted earnings per share increased 28 percent compared to the same period in the prior year, highlighted by improved operating results at our gas utility and coal mining segments and lower interest expense. Cooler weather benefited our gas utilities and tempered results at our electric utilities. Our electric utilities are experiencing continued retail load growth, particularly at Cheyenne Light which set a new all-time peak load during the quarter.
"We advanced several key initiatives during the quarter benefiting our growth strategy," continued Emery. "We achieved a significant milestone with the commencement of commercial operations at our new Cheyenne Prairie Generating Station. We also sold a combustion turbine for $22 million and announced an agreement to acquire a gas utility with 6,700 customers in northwest Wyoming.
"Our oil and gas subsidiary continued making excellent progress reducing capital costs in our Mancos Shale drilling program. We drilled, cased and cemented two wells during the quarter and are currently drilling a third well. Once we case and cement the third well, we plan to move the drilling rig to another surface pad to drill three additional wells. We will also begin completing the first three wells, which we expect to place on production starting in December and continuing into 2015.
"With strong financial performance this year, we are increasing our guidance for 2014 earnings, as adjusted, to $2.80 to $2.95 per share. Looking to next year, we are initiating guidance for 2015 earnings, as adjusted, of $2.90 to $3.10 per share," Emery concluded.
Three Months Ended Sept. Nine Months Ended Sept.
30, 30,
(in
millions,
except
per
share
amounts) 2014 2013 2014 2013
--------- ---- ---- ---- ----
Non-
GAAP
*:
Net
income,
as
adjusted
(non-
GAAP) $26.8 $21.1 $94.8 $77.7
===== ===== ===== =====
Earnings
per
share,
as
adjusted,
diluted
(non-
GAAP) $0.60 $0.47 $2.13 $1.75
===== ===== ===== =====
GAAP:
Net
income $26.8 $23.1 $94.8 $96.8
===== ===== ===== =====
Earnings
per
share,
diluted $0.60 $0.52 $2.13 $2.18
===== ===== ===== =====
* These are non-GAAP measures.
Accompanying schedules for the GAAP
to non-GAAP adjustment
reconciliations are provided below.
Black Hills Corp. highlights, recent regulatory filings and other updates include:
Utilities
-- On Oct. 14, 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. Closing is expected within six to
12 months.
-- On Oct. 1, Black Hills Power and Cheyenne Light placed into commercial
service the jointly-owned Cheyenne Prairie Generating Station. The $222
million, 132 megawatt natural gas-fired power plant was built on time
and on budget. New rates pertinent to the power plant were implemented
on Oct. 1 for Black Hills Power and Cheyenne Light in Wyoming and
interim rates were implemented for Black Hills Power in South Dakota.
-- 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 Cheyenne Prairie Generating Station. Black Hills
Power issued $85 million of 4.43 percent coupon first mortgage bonds due
Oct. 20, 2044, and Cheyenne Light issued $75 million of 4.53 percent
coupon first mortgage bonds due Oct. 20, 2044. Proceeds from Black Hills
Power's bond sale also funded the early redemption of its 5.35 percent
$12 million pollution control revenue bonds, originally due Oct. 1,
2024.
-- 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. New rates are based on a 9.9
percent return on equity and a capital structure of 53.3 percent equity
and 46.7 percent debt. The new rates will 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. New rates are based on a 9.9 percent return on
equity and a capital structure of 54 percent equity and 46 percent debt.
-- 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. On June 27, Black
Hills Power filed an application with the South Dakota Public Utilities
Commission seeking approval of a permit to construct this line. Approval
by the Wyoming Public Service Commission and South Dakota Public
Utilities Commission is anticipated in the fourth quarter of 2014.
-- 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 for
approximately 42 megawatts of seasonal firm capacity in 2017, 2018 and
2019, and up to 60 megawatts of eligible renewable energy resources to
serve its customers in southern Colorado. On July 31, our power
generation segment submitted solar and wind bids in response to the
request. A decision by the Colorado Public Utilities Commission on
Colorado Electric's portfolio of generation resources is expected by the
end of February 2015.
-- On April 30, Colorado Electric filed a rate request with the Colorado
Public Utilities Commission to recover increased operating expenses and
infrastructure investments, including those for the Busch Ranch Wind
Farm, placed in service late 2012. The filing also seeks to implement a
rider to recover a return on the construction costs for a $65 million
natural gas-fired combustion turbine that will replace the retired W.N.
Clark power plant. On Oct. 28, an administrative law judge issued a
recommended decision which incorporates a $2 million revenue increase,
9.83 percent return on equity and capital structure of 49.8 percent
equity and 50.2 percent debt. The recommended decision also approves the
implementation of the plant construction rider. The recommended decision
is subject to exceptions and final commission approval with rates
effective by the end of 2014.
-- On April 29, Kansas Gas filed a rate request with the Kansas Corporation
Commission to increase its annual revenue primarily to recover
infrastructure investments made since its last rate filing in late 2006.
On Oct. 24, a settlement agreement was reached between Kansas Gas,
commission staff and intervenors to increase base rates by $5.2 million.
A hearing is scheduled for Nov. 12 and a final commission order is
expected by Jan. 6, 2015, with new rates effective by mid-January.
-- On March 21, Black Hills Power filed a rate request with the South
Dakota Public Utilities Commission to increase annual revenue by $14.6
million to recover operating expenses and infrastructure investments,
primarily for the Cheyenne Prairie Generation Station. The filing seeks
a 10.25 percent return on equity and a capital structure of 53.3 percent
equity and 46.7 percent debt. Interim rates were implemented on Oct. 1
coincident with Cheyenne Prairie Generating Station commercial
operations. Hearings regarding the request are scheduled for Jan. 27-30,
2015.
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, provide plant-related
administrative services and share with Gillette in savings from
wholesale power purchases made on behalf of the city when power costs
are less than operating the generating unit.
-- Oil and gas drilled, cased and cemented two Mancos Shale wells in the
southern Piceance Basin during the quarter and is currently drilling a
third Mancos Shale well.
Corporate
-- On Oct. 29, Black Hills announced executive leadership changes. Anthony
Cleberg, current executive vice president and chief financial officer,
will retire by the end of March 2015. Richard Kinzley, current vice
president and controller, will be appointed senior vice president and
chief financial officer effective Jan. 1, 2015. In addition, Brian
Iverson was appointed senior vice president, regulatory, government
affairs and assistant general counsel effective Nov. 1, 2014.
-- On Oct. 28, Black Hills' board of directors declared a quarterly
dividend on the common stock. Shareholders of record at the close of
business on Nov. 17, 2014, will receive $0.39 per share, equivalent to
an annual dividend rate of $1.56 per share, payable on Dec. 1, 2014.
-- The quarter included approximately $1.3 million income tax benefit based
on information received from the Internal Revenue Service related to the
2007 through 2009 tax audits.
BLACK HILLS CORPORATION
CONSOLIDATED FINANCIAL RESULTS
(Minor differences may result due to rounding.)
Three Months Ended Sept. Nine Months Ended Sept.
30, 30,
2014 2013 2014 2013
---- ---- ---- ----
(in millions)
Net income (loss):
Utilities:
Electric $18.2 $15.1 $44.2 $38.1
Gas 1.6 (1.5) 28.3 20.2
--- ---- ---- ----
Total Utilities Group 19.8 13.6 72.5 58.3
---- ---- ---- ----
Non-regulated Energy:
Power generation 7.8 6.7 23.1 17.4
Coal mining 2.6 2.2 7.1 5.2
Oil and gas (3.1) (1.7) (6.8) (3.7)
---- ---- ---- ----
Total Non-regulated
Energy Group 7.3 7.2 23.4 18.9
--- --- ---- ----
Corporate and
Eliminations (a) (0.3) 2.5 (1.1) 19.7
---- --- ---- ----
Net income (loss) $26.8 $23.1 $94.8 $96.8
===== ===== ===== =====
(a) Financial results include a $2
million and a $19 million
after-tax non-cash mark-to-
market gain for the three and
nine months ended September
30, 2013, respectively on
certain interest rate swaps.
These same interest rate swaps
were settled in November 2013.
Three Months Ended Nine Months Ended Sept.
Sept. 30, 30,
2014 2013 2014 2013
---- ---- ---- ----
Weighted
average
common
shares
outstanding
(in
thousands):
Basic 44,415 44,201 44,382 44,143
Diluted 44,608 44,457 44,584 44,395
Earnings
per
share:
Basic -
Total
Basic
Earnings
Per
Share $0.60 $0.52 $2.14 $2.19
===== ===== ===== =====
Diluted -
Total
Diluted
Earnings
Per
Share $0.60 $0.52 $2.13 $2.18
===== ===== ===== =====
2014 EARNINGS GUIDANCE INCREASED
The company raised its guidance for 2014 earnings, as adjusted, to $2.80 to $2.95 per share, from $2.65 to $2.85 per share.
2015 EARNINGS GUIDANCE INITIATED
Black Hills initiated guidance for 2015 earnings, as adjusted, of $2.90 to $3.10 per share based on the following assumptions:
-- Capital spending of $432 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 13.5 to 15.0 billion
cubic feet equivalent;
-- Oil and natural gas annual average NYMEX prices of $3.85 per million
British thermal units for natural gas and $82.00 per barrel for oil;
production-weighted average well-head prices of $2.47 per MMBtu and
$72.00 per Bbl of oil, and average hedged prices received of $2.60 per
MMBtu and $73.99 per Bbl;
-- Oil and natural gas depletion expense in the range of $2.35 to $2.55 per
million cubic feet equivalent;
-- 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
Black Hills will host a live conference call and webcast at 11 a.m. ET on Tuesday, Nov. 4, 2014, 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 877-474-9502 if calling within the United States. International callers can call 857-244-7555. All callers need to enter the pass code 50537736 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, Nov. 25, 2014, at 888-286-8010 in the United States and at 617-801-6888 for international callers. The replay pass code is 32304246.
USE OF NON-GAAP FINANCIAL MEASURE
As noted in this news release, in addition to presenting our earnings information in conformity with Generally Accepted Accounting Principles, the company provided non-GAAP earnings data reflecting adjustments for special items as specified in the GAAP to non-GAAP adjustment reconciliation table below. Net income (loss), as adjusted, is defined as Net income (loss), adjusted for expenses, gains and losses that the company believes do not reflect the company's core operating performance. Black Hills believes that non-GAAP financial measures are useful to investors because the items excluded may not be indicative of the company's continuing operating results. Company 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.
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.
GAAP TO NON-GAAP ADJUSTMENT RECONCILIATION
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
(In millions,
except per share
amounts) 2014 2013 2014 2013
---- ---- ---- ----
(after-tax) Income EPS Income EPS Income EPS Income EPS
------ --- ------ --- ------ ---
Net income (loss)
(GAAP) $26.8 $0.60 $23.1 $0.52 $94.8 $2.13 $96.8 $2.18
----- ----- ----- ----- ----- ----- ----- -----
Adjustments,
after-tax:
Unrealized (gain)
loss on certain
interest rate
swaps - - (2.0) (0.05) - - (19.1) (0.43)
Total adjustments - - (2.0) (0.05) - - (19.1) (0.43)
--- --- ---- ----- --- --- ----- -----
Net income
(loss), as
adjusted (non-
GAAP) $26.8 $0.60 $21.1 $0.47 $94.8 $2.13 $77.7 $1.75
===== ===== ===== ===== ===== ===== ===== =====
BUSINESS UNIT PERFORMANCE SUMMARY
Business Group highlights for the three months ended Sept. 30, 2014, compared to the three months ended Sept. 30, 2013, 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 third quarter ended Sept. 30, 2014, was $20 million, compared to $14 million in 2013.
Electric Utilities
Three Months Ended Sept.
30, Variance Nine Months Ended Sept. 30, Variance
2014 2013 2014 vs. 2014 2013 2014 vs.
2013 2013
---- ---- --------- ---- ---- ---------
(in millions)
Gross margin $97.3 $99.0 $(1.7) $280.9 $277.6 $3.3
----- ----- ----- ------ ------ ----
Operations and
maintenance 39.1 41.1 (2.0) 121.9 119.4 2.5
Depreciation and
amortization 19.6 19.4 0.2 58.0 58.2 (0.2)
---- ---- ---- ----
Operating income 38.7 38.5 0.2 100.9 100.1 0.8
Interest expense,
net (11.7) (14.1) 2.4 (35.6) (42.3) 6.7
Other (income)
expense, net 0.3 - 0.3 0.9 0.5 0.4
Income tax
benefit
(expense) (9.1) (9.3) 0.2 (22.2) (20.2) (2.0)
---- ---- --- ----- ----- ----
Net income (loss) $18.2 $15.1 $3.1 $44.2 $38.1 $6.1
===== ===== ==== ===== ===== ====
Three Months Ended Sept. 30, Nine Months Ended Sept. 30,
2014 2013 2014 2013
---- ---- ---- ----
Operating Statistics:
Retail sales - MWh 1,250,486 1,227,791 3,563,216 3,470,005
Contracted wholesale
sales -MWh 83,714 87,092 250,941 268,529
Off-system sales - MWh 234,009 372,216 833,833 1,090,340
------- ------- ------- ---------
Total electric sales -
MWh 1,568,209 1,687,099 4,647,990 4,828,874
========= ========= ========= =========
Total gas sales -
Cheyenne Light -Dth 391,441 366,483 3,102,705 3,220,754
------- ------- --------- ---------
Regulated power plant
availability:
Coal-fired plants (a) 97.0% 97.6% 92.4% 96.8%
Other plants (b) 95.6% 95.8% 87.9% 96.7%
Total availability 96.2% 96.7% 89.8% 96.7%
(a) The nine months ended Sept. 30,
2014 reflects a planned annual
outage at Neil Simpson II and
an unplanned outage for a
catalyst repair at Wygen III.
(b) The nine months ended Sept. 30,
2014, includes a planned
outage at Ben French CT's #1
and #2 for a controls upgrade,
and an unplanned outage due to
a turbine bearing replacement
and combustor upgrade at
Pueblo Airport Generation
Station.
Third Quarter 2014 Compared with Third Quarter 2013
Gross margin decreased primarily due to a 26 percent decrease in cooling degree days compared to the same period in the prior year resulting in a $3.4 million decrease on lower demand and residential megawatt hours sold. Wholesale margins were also impacted by plant outages affecting unit specific contracts, resulting in a $0.7 million decrease in wholesale margins. These decreases were partially offset by increased rider margins of $1.4 million due to a return on additional investment in our generating facilities, and $1.0 million driven by service revenue on industrial load growth at Colorado Electric. Industrial megawatt hours sold increased 12 percent compared to the same period in the prior year, primarily driven by load growth at Cheyenne Light.
Operations and maintenance decreased primarily due to decreases in corporate expense allocations and outside services.
Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.
Income tax benefit (expense): The effective tax rate is lower in 2014 primarily due to a favorable true-up to the filed 2013 income tax return, in addition to an increase in flow-through tax adjustments.
Gas Utilities
Three Months Ended Sept.
30, Variance Nine Months Ended Sept. 30, Variance
2014 2013 2014 vs. 2014 2013 2014 vs.
2013 2013
---- ---- --------- ---- ---- ---------
(in millions)
Gross margin $42.2 $40.2 $2.0 $173.6 $165.1 $8.5
----- ----- ---- ------ ------ ----
Operations and
maintenance 31.6 30.5 1.1 100.5 95.5 5.0
Depreciation and
amortization 6.6 6.6 - 19.7 19.7 -
--- --- ---- ----
Operating income 3.9 3.1 0.8 53.5 49.8 3.7
Interest expense,
net (3.8) (6.0) 2.2 (11.3) (18.2) 6.9
Other expense
(income), net - - - - - -
Income tax
benefit
(expense) 1.4 1.4 - (13.8) (11.4) (2.4)
--- --- --- ----- ----- ----
Net income (loss) $1.6 $(1.5) $3.1 $28.3 $20.2 $8.1
==== ===== ==== ===== ===== ====
Three Months Ended Sept.
30, Nine Months Ended Sept. 30,
2014 2013 2014 2013
---- ---- ---- ----
Operating
Statistics:
Total
gas
sales
-
Dth 6,112,691 5,402,838 42,893,563 40,201,635
Total
transport
volumes
-
Dth 14,360,388 14,205,801 50,385,306 47,415,540
Third Quarter 2014 Compared with Third Quarter 2013
Gross margin increased primarily due to cooler weather compared to the same period in the prior year resulting in higher residential and commercial volumes sold. Heating degree days were 73 percent higher for the three months ended September 30, 2014, compared to the same period in the prior year and 6 percent higher than normal. Also, a return on additional capital investments flowing through capital trackers resulted in increased surcharge revenue of $0.5 million.
Operations and maintenance increased primarily due to an increase in property taxes, and allowance for uncollectible account expense, partially offset by a decrease in corporate expense allocations.
Interest expense, net decreased primarily due to lower interest rates from refinancing higher cost debt in the fourth quarter of 2013.
Income tax benefit (expense): The effective tax rate for 2014 reflects a tax benefit due primarily to a favorable true-up to the filed 2013 income tax return, including an increase in an estimated flow-through tax adjustment.
Non-Regulated Energy Group
Net income (loss) from the Non-regulated Energy group for the three months ended Sept. 30, 2014, was $7.3 million, compared to Net income (loss) of $7.2 million for the same period in 2013.
Power Generation
Three Months Ended Sept.
30, Variance Nine Months Ended Sept. 30, Variance
2014 2013 2014 vs. 2014 2013 2014 vs.
2013 2013
---- ---- --------- ---- ---- ---------
(in millions)
Revenue $22.0 $22.0 $ - $66.3 $62.5 $3.8
----- ----- --- --- ----- ----- ----
Operations and
maintenance 7.3 6.3 1.0 23.7 22.3 1.4
Depreciation and
amortization 1.1 1.3 (0.2) 3.5 3.8 (0.3)
--- --- ---- --- --- ----
Operating income 13.6 14.3 (0.7) 39.1 36.3 2.8
Interest expense,
net (0.9) (2.8) 1.9 (2.8) (8.2) 5.4
Other (income)
expense, net - - - - - -
Income tax
benefit
(expense) (4.9) (4.8) (0.1) (13.3) (10.7) (2.6)
---- ---- ---- ----- ----- ----
Net income (loss) $7.8 $6.7 $1.1 $23.1 $17.4 $5.7
==== ==== ==== ===== ===== ====
Three Months Ended Nine Months Ended
Sept. 30, Sept. 30,
2014 2013 2014 2013
---- ---- ---- ----
Operating
Statistics:
Contracted fleet
power plant
availability -
Coal-fired plants 96.1% 100.0% 98.0% 98.0%
Gas-fired plants 99.2% 99.2% 98.7% 99.0%
Total availability 98.5% 99.4% 98.6% 98.8%
Third Quarter 2014 Compared with Third Quarter 2013
Revenue was comparable to the prior year reflecting an increase in megawatt hours delivered under PPAs, offset by a decrease in off-system sales from Wygen I.
Operations and maintenance increased primarily due to an increase in property taxes and repairs and maintenance at Colorado IPP, partially offset by a decrease in allocated corporate expenses.
Depreciation and amortization was comparable to the same period in the prior year. The generating facility located in Pueblo, Colo., 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.
Interest expense, net decreased primarily due to refinancing higher cost project debt and settling associated interest rate swaps in the fourth quarter of 2013.
Income tax benefit (expense): The effective tax rate is lower in 2014 compared to 2013 due to a favorable current year true-up to the filed 2013 income tax return.
Coal Mining
Three Months Ended Sept. Variance Nine Months Ended Sept.
30, 30, Variance
2014 2013 2014 vs. 2014 2013 2014 vs.
2013 2013
---- ---- --------- ---- ---- ---------
(in millions)
Revenue $15.6 $15.3 $0.3 $45.7 $43.2 $2.5
----- ----- ---- ----- ----- ----
Operations and
maintenance 9.9 10.2 (0.3) 30.0 29.6 0.4
Depreciation,
depletion and
amortization 2.5 2.9 (0.4) 7.8 8.7 (0.9)
--- --- ---- --- --- ----
Operating income
(loss) 3.2 2.2 1.0 7.9 4.9 3.0
Interest
(expense)
income, net (0.1) (0.2) 0.1 (0.3) (0.5) 0.2
Other income
(expense), net 0.5 0.6 (0.1) 1.7 1.7 -
Income tax
benefit
(expense) (0.9) (0.5) (0.4) (2.2) (1.0) (1.2)
---- ---- ---- ---- ---- ----
Net income (loss) $2.6 $2.1 $0.5 $7.1 $5.2 $1.9
==== ==== ==== ==== ==== ====
Three Months Ended Sept. Nine Months Ended Sept.
30, 30,
2014 2013 2014 2013
---- ---- ---- ----
Operating
Statistics: (in thousands)
Tons of coal
sold 1,082 1,133 3,232 3,265
Cubic yards of
overburden
moved 1,005 685 2,925 2,674
Revenue per ton $14.38 $13.52 $14.15 $13.24
Third Quarter 2014 Compared with Third Quarter 2013
Revenue increased primarily due to a 6 percent increase in price per ton sold, partially offset by a 5 percent decrease in tons sold. Pricing was favorably impacted by a coal contract price increase with the third-party operator of the Wyodak plant, 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. 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 lower corporate allocated costs and a gain on the sale of land and equipment, partially offset by increased diesel consumption costs.
Depreciation, depletion and amortization decreased primarily due to lower depreciation on mine assets and mine reclamation asset retirement costs.
Income tax benefit (expense): The effective tax rate in 2014 is higher due to the reduced impact of the tax benefit of percentage depletion, and an unfavorable true-up to the filed 2013 income tax return.
Oil and Gas
Three Months Ended Sept. 30, Variance Nine Months Ended Sept. 30, Variance
2014 2013 2014 vs. 2013 2014 2013 2014 vs. 2013
---- ---- ------------- ---- ---- -------------
(in millions)
Revenue $13.5 $14.4 $(0.9) $43.5 $41.6 $1.9
----- ----- ----- ----- ----- ----
Operations and
maintenance 10.3 10.7 (0.4) 31.7 30.9 0.8
Depreciation,
depletion and
amortization 7.6 6.2 1.4 21.5 16.7 4.8
---
Operating income (4.5) (2.4) (2.1) (9.8) (6.1) (3.7)
Interest income
(expense), net (0.4) (0.3) - (1.3) (0.3) (1.0)
Other (income)
expense, net - 0.1 (0.1) 0.1 0.1 -
Income tax
benefit
(expense) 1.7 1.0 0.7 4.1 2.6 1.5
--- --- --- --- --- ---
Net income (loss) $(3.1) $(1.7) $(1.4) $(6.8) $(3.7) $(3.1)
===== ===== ===== ===== ===== =====
Three Months Ended Sept. 30, Percentage Increase Nine Months Ended Sept. 30, Percentage Increase
2014 2013 (Decrease) 2014 2013 (Decrease)
---- ---- --------- ---- ---- ---------
Operating Statistics:
Bbls of crude oil sold 82,640 84,260 (2)% 249,130 246,367 1%
Mcf of natural gas
sold 1,856,138 1,765,622 5% 5,456,928 5,282,961 3%
Gallons of NGL sold 1,387,460 988,682 40% 4,287,292 2,830,216 51%
Mcf equivalent sales 2,550,187 2,412,422 6% 7,564,179 7,165,479 6%
Depletion expense/Mcfe $2.51 $2.16 16% $2.38 $1.92 24%
Three Months Ended Sept. 30, 2014 Three Months Ended Sept. 30, 2013
--------------------------------- ---------------------------------
Crude Oil Natural Gas Natural Crude Oil Natural Gas Natural
Gas Gas
Liquids Liquids
Average
Prices (Bbl) (MMcf) (gallons) (Bbl) (MMcf) (gallons)
------- ---- ----- -------- ---- ----- --------
Average
hedged
price
received $80.42 $2.70 $0.85 $94.32 $2.82 $0.71
Average
well-
head
price $85.15 $1.73 $97.75 $2.27
Nine Months Ended Sept. 30, 2014 Nine Months Ended Sept. 30, 2013
-------------------------------- --------------------------------
Crude Oil Natural Gas Natural Crude Oil Natural Gas Natural
Gas Gas
Liquids Liquids
Average
Prices (Bbl) (MMcf) (gallons) (Bbl) (MMcf) (gallons)
------- ---- ----- -------- ---- ----- --------
Average
hedged
price
received $83.19 $3.07 $0.92 $92.60 $2.69 $0.79
Average
well-
head
price $88.18 $2.57 $92.04 $2.05
Third Quarter 2014 Compared with Third Quarter 2013
Revenue decreased primarily due to a 15 percent decrease in the average hedged price received for crude oil sold, and a 4 percent decrease in the average hedged price received for natural gas sold, partially offset by a 6 percent production increase driven by two new Piceance Mancos Shale wells placed on production in the first quarter of 2014.
Operations and maintenance decreased primarily due to lower employee costs.
Depreciation, depletion and amortization increased primarily due to a higher depletion rate applied to greater production.
Income tax (expense) benefit: Each period presented reflects a tax benefit. The tax benefit for 2014 was impacted by an unfavorable true-up to the filed 2013 income tax return.
Corporate Activities
Third Quarter 2014 Compared with Third Quarter 2013
Net loss for Corporate activity was $0.3 million for the three months ended September 30, 2014, compared to net income of $2.5 million for the three months ended September 30, 2013. The variance from the prior year was primarily due to:
-- The settlement of the de-designated interest rate swaps in the fourth
quarter of 2013 resulted in no mark-to-market activity for the three
months ended September 30, 2014, compared to a mark-to-market gain of $3
million recorded for the three months ended September 30, 2013.
-- The income for the three months ended September 30, 2014, included lower
interest expense compared to the three months ended September 30, 2013,
as a result of lower interest rate debt from refinancing activities in
fourth quarter 2013, and the avoided settlement cost on the
de-designated interest rate swaps, which were terminated in fourth
quarter 2013.
ABOUT BLACK HILLS CORP.
Black Hills Corp. (NYSE: BKH) is a growth-oriented, vertically-integrated energy company with a tradition of exemplary service and a vision to be the energy partner of choice. 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 Corp.'s 1,948 employees partner to produce results that improve life with energy. More information is available at www.blackhillscorp.com.
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 2014 and 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 reserves located in the San Juan and southern Piceance Basins;
-- Our ability to provide accurate estimates of proved crude oil and gas
reserves and future production and associated 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.
(Minor differences may result due to rounding.)
Consolidating Income Statement
------------------------------
Three Months Ended Electric Power Electric Power Other Inter-
Sept. 30, 2014 Utilities (a) Generation Utility Generation Co
(a) Inter-Co Inter-Co Eliminations
Lease Elim Lease Elim
Gas Utilities Coal Mining Oil and Gas Corporate (a) (a) Total
-------------- ------------- ----------- ----------- ----------- --------- ----------- ----------- ------------- -----
(in millions)
Revenue $171.4 $78.7 $1.6 $6.9 $13.5 $ - $ - $ - $ - $272.1
Intercompany
revenue 3.2 - 20.4 8.7 - 52.4 - 0.5 (85.2) -
Fuel, purchased
power and cost of
gas sold 77.2 36.5 - - - - 1.1 - (30.1) 84.7
---- ---- --- --- --- --- --- --- ----- ----
Gross margin 97.3 42.2 22.0 15.6 13.5 52.4 (1.1) 0.5 (55.1) 187.4
---- ---- ---- ---- ---- ---- ---- --- ----- -----
Operations and
maintenance 39.1 31.6 7.3 9.9 10.3 50.5 - - (53.2) 95.5
Depreciation,
depletion and
amortization 19.6 6.6 1.1 2.5 7.6 2.0 (3.3) 3.2 (2.0) 37.5
Operating income 38.7 3.9 13.6 3.2 (4.5) (0.1) 2.2 (2.7) 0.1 54.4
---- --- ---- --- ---- ---- --- ---- --- ----
Interest expense,
net (12.8) (3.8) (1.1) (0.1) (0.6) (12.5) - - 13.5 (17.4)
Interest rate
swaps -
unrealized (loss)
gain - - - - - - - - - -
Interest income 1.1 - 0.2 - 0.2 12.2 - - (13.2) 0.6
Other income
(expense) 0.3 - - 0.5 - 9.8 - - (10.1) 0.6
Income tax benefit
(expense) (9.1) 1.4 (4.9) (0.9) 1.7 0.3 (0.8) 1.0 - (11.3)
---- --- ---- ---- --- --- ---- --- --- -----
Net income (loss) $18.2 $1.6 $7.8 $2.6 $(3.1) $9.7 $1.4 $(1.7) $(9.7) $26.8
===== ==== ==== ==== ===== ==== ==== ===== ===== =====
(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
------------------------------
Nine Months Ended Electric Power Electric Power Other Inter-Co
Sept. 30, 2014 Utilities (a) Generation Utility Generation Eliminations
(a) Inter-Co Inter-Co
Lease Elim Lease Elim(a)
Gas Utilities Coal Mining Oil and Gas Corporate (a) Total
-------------- ------------- ----------- ----------- ----------- --------- ----------- -------------- --------------- -----
(in millions)
Revenue $508.2 $440.6 $4.1 $19.1 $43.5 $ - $ - $ - $ - $1,015.5
Intercompany
revenue 10.3 - 62.2 26.6 - 164.6 - 1.5 (265.3) -
Fuel, purchased
power and cost of
gas sold 237.7 266.9 - - - 0.1 3.1 - (91.3) 416.5
Gross margin 280.9 173.6 66.3 45.7 43.5 164.5 (3.1) 1.5 (174.0) 599.0
----- ----- ---- ---- ---- ----- ---- --- ------ -----
Operations and
maintenance 121.9 100.5 23.7 30.0 31.7 157.9 - - (167.5) 298.2
Depreciation,
depletion and
amortization 58.0 19.7 3.5 7.8 21.5 5.5 (9.8) 9.6 (5.5) 110.3
Operating income 100.9 53.5 39.1 7.9 (9.8) 1.1 6.7 (8.0) (0.9) 190.6
----- ---- ---- --- ---- --- --- ---- ---- -----
Interest expense,
net (39.2) (11.8) (3.3) (0.4) (2.0) (38.0) - - 42.6 (52.1)
Interest rate
swaps -
unrealized (loss)
gain - - - - - - - - - -
Interest income 3.6 0.4 0.5 - 0.7 37.0 - - (40.8) 1.5
Other income
(expense) 0.9 - - 1.7 0.1 43.1 - - (43.8) 2.1
Income tax benefit
(expense) (22.2) (13.8) (13.3) (2.2) 4.1 (0.6) (2.5) 3.0 0.1 (47.3)
---- ---- --- --- -----
Net income (loss) $44.2 $28.3 $23.1 $7.1 $(6.8) $42.6 $4.3 $(5.1) $(42.9) $94.8
===== ===== ===== ==== ===== ===== ==== ===== ====== =====
(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 Electric Power Electric Power Other Inter-
Sept. 30, 2013 Utilities (a) Generation Utility Generation Co
(a) Inter-Co Inter-Co Eliminations
Lease Elim Lease Elim
Gas Utilities Coal Mining Oil and Gas Corporate (a) (a) Total
--------------- ------------- ----------- ----------- ----------- --------- ----------- ----------- ------------- -----
(in millions)
Revenue $169.4 $67.8 $1.5 $6.7 $14.4 $ - $ - $ - $ - $259.9
Intercompany
revenue 2.0 - 20.4 8.6 - 53.4 - 0.5 (84.9) -
Fuel, purchased
power and cost of
gas sold 72.4 27.6 - - - 0.1 0.9 - (29.5) 71.5
Gross margin 99.0 40.3 22.0 15.3 14.4 53.3 (0.9) 0.5 (55.4) 188.4
---- ---- ---- ---- ---- ---- ---- --- ----- -----
Operations and
maintenance 41.2 30.5 6.3 10.2 10.6 50.0 - - (52.0) 96.7
Depreciation,
depletion and
amortization 19.4 6.6 1.3 2.9 6.1 2.7 (3.2) 3.1 (2.8) 36.2
Operating income 38.5 3.1 14.3 2.2 (2.4) 0.6 2.3 (2.6) (0.6) 55.4
---- --- ---- --- ---- --- --- ---- ---- ----
Interest expense,
net (15.7) (6.1) (3.1) (0.2) (0.8) (17.9) - - 20.6 (23.2)
Interest rate
swaps -
unrealized (loss)
gain - - - - - 3.2 - - - 3.2
Interest income 1.6 0.1 0.2 - 0.4 17.8 - - (19.6) 0.5
Other income
(expense) - - - 0.6 0.1 2.3 - - (2.5) 0.5
Income tax benefit
(expense) (9.3) 1.4 (4.8) (0.5) 1.0 (1.3) (0.8) 1.0 - (13.3)
Net income (loss) $15.1 $(1.5) $6.7 $2.2 $(1.7) $4.6 $1.5 $(1.6) $(2.0) $23.1
===== ===== ==== ==== ===== ==== ==== ===== ===== =====
(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.
Consolidating Income Statement
------------------------------
Nine Months Ended Electric Power Electric Power Other Inter-Co
Sept. 30, 2013 Utilities (a) Generation Utility Generation Eliminations
(a) Inter-Co Inter-Co
Lease Elim Lease Elim
Gas Utilities Coal Mining Oil and Gas Corporate (a) (a) Total
-------------- ------------- ----------- ----------- ----------- --------- ----------- ----------- --------------- -----
(in millions)
Revenue $482.2 $373.4 $3.6 $19.5 $41.6 $ - $ - $ - $ - $920.4
Intercompany
revenue 9.8 - 58.8 23.7 - 164.6 - 1.4 (258.3) -
Fuel, purchased
power and cost of
gas sold 214.4 208.4 - - - 0.1 2.7 - (86.8) 338.8
Gross margin 277.6 165.1 62.5 43.2 41.6 164.5 (2.7) 1.4 (171.5) 581.6
----- ----- ---- ---- ---- ----- ---- --- ------ -----
Operations and
maintenance 119.4 95.5 22.3 29.6 30.9 150.5 - - (157.1) 291.0
Depreciation,
depletion and
amortization 58.2 19.7 3.8 8.7 16.7 8.8 (9.8) 8.7 (8.8) 106.1
Operating income 100.1 49.8 36.3 4.9 (6.1) 5.2 7.1 (7.3) (5.6) 184.4
----- ---- ---- --- ---- --- --- ---- ---- -----
Interest expense,
net (46.2) (19.1) (8.9) (0.5) (1.6) (57.6) - - 64.7 (69.2)
Interest rate
swaps -
unrealized (loss)
gain - - - - - 29.4 - - - 29.4
Interest income 3.9 0.9 0.6 - 1.3 52.7 - - (58.1) 1.3
Other income
(expense) 0.5 - - 1.7 0.1 28.9 - - (29.8) 1.4
Income tax benefit
(expense) (20.2) (11.4) (10.7) (1.0) 2.6 (9.9) (2.6) 2.7 - (50.5)
Net income (loss) $38.1 $20.2 $17.4 $5.2 $(3.7) $48.6 $4.5 $(4.6) $(28.7) $96.8
===== ===== ===== ==== ===== ===== ==== ===== ====== =====
(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.
Investor Relations:
Jerome Nichols
Phone 605-721-1171
Email jerome.nichols@blackhillscorp.com
Media Contact:
24-hour Media Assistance 866-243-9002
SOURCE Black Hills Corp.
