MDU Resources Group, Inc. (NYSE:MDU) today reported third quarter
consolidated adjusted earnings of $92.3 million, or 49 cents per share,
compared to $71.9 million, or 38 cents per share in the third quarter of
2012. Consolidated GAAP earnings were $84.3 million, or 44 cents per
common share, compared to a loss of $29.8 million, or 16 cents per
common share for the third quarter of 2012. For an explanation of
non-GAAP earnings adjustments, see the Reconciliation of GAAP to
Adjusted Earnings and the Use of Non-GAAP Financial Measures sections
later in this press release.
"We are seeing excellent results from our businesses' capital
investments and strategic focus continuing the trend we have had for the
last three quarters," said David L. Goodin, president and CEO of MDU
Resources. "Our strong operations have produced 38 percent growth
year-to-date in consolidated adjusted earnings per share compared to
last year. These results reflect the value of our diversified model with
all of our business segments contributing to this success.
"Our exploration and production business continued to outperform its
year-over-year production target. Fidelity increased third-quarter oil
production by 37 percent from the same period last year, and is well
positioned to deliver on its annual growth target of 30 to 35 percent."
Fidelity's success with improved completion techniques in the Bakken
helped increase oil production in that play by 41 percent in the third
quarter. While the Bakken continues to be the largest source of
Fidelity's production, the Paradox Basin is becoming an increasingly
important part of the company's production mix and growth platform.
Fidelity's latest Paradox well, the Cane Creek Unit 36-1, has been
flowing consistently above 1,250 barrels per day since Oct. 11 with a
flowing pressure of approximately 3,400 psi.
The construction materials and services businesses sustained its growth
in volumes and margins with combined earnings of $61.4 million, compared
to $51.8 million last year. The construction materials group had it's
best quarter since 2007. On a combined basis, the construction
businesses' earnings are 29 percent higher for the trailing twelve
months ended Sept. 30, compared to 2012 annual earnings. Combined
backlog increased to $958 million compared to $834 million a year ago.
This includes the largest road construction contract ever awarded to
Knife River -- a $55 million project in western North Dakota. Knife
River began work on that project in September.
The pipeline and energy services business increased earnings to $5.3
million, $2.0 million higher than third quarter of last year, largely on
the strength of its investment in the Pronghorn natural gas and oil
midstream assets in May 2012 and lower operation and maintenance
expense. Construction of a diesel topping plant near Dickinson, N.D. in
the Bakken area is progressing on schedule with expected completion in
late 2014.
The pipeline group continues to evaluate routes for a 400-mile natural
gas pipeline that it plans to build from western North Dakota to western
Minnesota. The alternate routes being evaluated would give customers
access to broader market diversity, in addition to serving industrial
load in eastern North Dakota. Once built, the pipeline would provide
much-needed takeaway capacity for the Bakken's rapidly growing natural
gas production, which in August reached a milestone of 1 billion cubic
feet per day. In addition, on Oct. 31, WBI Energy Transmission filed a
rate increase request with the Federal Energy Regulatory Commission for
an increase of $28.9 million annually to cover increased investments of
$312 million, increased operating costs, and the effects of lower
storage and off system volumes. This is the first case the company has
filed in approximately 14 years.
The electric utility business increased earnings to $11.4 million as it
continued to experience growth in customers and electricity sales
related to Bakken production activity and the ancillary businesses
attracted by Bakken oil development. The natural gas business
experienced a normal seasonal loss of $11.2 million. The loss was larger
than last year principally because of higher operation and maintenance
expense, the result of higher payroll related to employee additions to
further support customer growth and pipeline safety.
Adjusted consolidated earnings for the nine months ended Sept. 30 were
$199.6 million, or $1.05 per share, compared to $142.7 million, or 76
cents per share a year ago. Consolidated year-to-date GAAP earnings were
$187.0 million, or 99 cents per share, compared to $59.7 million, or 32
cents per share for the nine months ended Sept. 30, 2012.
"The focus that our businesses have placed on growth is producing strong
results, and I'm pleased with our progress through the first nine months
of the year," Goodin said. "Considering earnings to this point, we are
increasing our adjusted earnings per share guidance range for 2013 to
$1.35 to $1.45. Where we end the year will be dependent on several
factors - commodity prices being one. We have seen a widening of
differentials for oil and weather is certainly a factor for our
construction businesses as to whether we can continue work in our
northern tier states in this fourth quarter."
The company will host a webcast at 10 a.m. EDT Friday, Nov. 1, to
discuss earnings results. The event can be accessed at www.mdu.com.
Webcast and audio replays will be available. The dial-in number for
audio replay is (855) 859-2056, or (404) 537-3406 for international
callers, conference ID 74400416.
About MDU Resources
MDU Resources Group, Inc., a member of the S&P MidCap 400 index,
provides value-added natural resource products and related services that
are essential to energy and transportation infrastructure, including
regulated utilities and pipelines, exploration and production, and
construction materials and services. For more information about MDU
Resources, see the company's website at www.mdu.com
or contact the Investor Relations Department at investor@mduresources.com.
Performance Summary and Future Outlook
The following information highlights the key growth strategies,
projections and certain assumptions for the company and its subsidiaries
and other matters for each of the company’s businesses. Many of these
highlighted points are “forward-looking statements.” There is no
assurance that the company’s projections, including estimates for growth
and changes in earnings, will in fact be achieved. Please refer to
assumptions contained in this section, as well as the various important
factors listed at the end of this document under the heading “Risk
Factors and Cautionary Statements that May Affect Future Results.”
Changes in such assumptions and factors could cause actual future
results to differ materially from growth and earnings projections.
Earnings by Segment
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Third
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Third
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YTD
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YTD
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Quarter
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Quarter
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Sept. 30,
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Sept. 30,
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2013
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2012
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2013
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2012
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Adjusted
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Adjusted
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Adjusted
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Adjusted
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Business Line
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Earnings
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Earnings
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Earnings
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Earnings
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(In millions)
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Exploration and Production
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$
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25.3
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$
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13.8
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$
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74.1
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$
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44.2
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Regulated
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Electric and natural gas utilities
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.2
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2.2
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41.1
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33.3
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Pipeline and energy services
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5.3
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3.3
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10.3
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8.6
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Construction Materials and Services
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61.4
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51.8
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75.3
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54.7
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Other and eliminations
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.1
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.8
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(1.2
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1.9
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Adjusted earnings
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$
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92.3
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$
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71.9
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$
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199.6
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$
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142.7
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Reconciliation of GAAP to Adjusted Earnings
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Third
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Third
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YTD
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YTD
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Quarter
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Quarter
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Sept. 30,
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Sept. 30,
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2013
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2012
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2013
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2012
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Earnings
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Earnings
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Earnings
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Earnings
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(In millions, except per share amounts)
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Earnings (loss) on common stock
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$
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84.3
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$
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(29.8
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)
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$
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187.0
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$
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59.7
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Adjustments net of tax:
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Discontinued operations
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.1
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.1
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.2
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(4.8
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)
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Unrealized commodity derivatives loss
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7.9
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.7
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3.4
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.2
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Natural gas gathering asset impairment
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—
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—
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9.0
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1.7
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Net benefit related to natural gas gathering operations litigation
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—
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—
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—
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(15.0
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)
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Write-down of oil and natural gas properties
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—
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100.9
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—
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100.9
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Adjusted earnings
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$
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92.3
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$
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71.9
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$
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199.6
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$
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142.7
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Adjusted earnings per share
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$
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.49
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$
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.38
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$
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1.05
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$
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.76
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On a consolidated basis, the following information highlights the key
growth strategies, projections and certain assumptions for the company:
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Adjusted earnings per common share for 2013 are projected in the range
of $1.35 to $1.45, an increase from prior guidance of $1.30 to $1.40.
GAAP earnings guidance for 2013 is in the range of $1.30 to $1.40 per
share. Unrealized commodity derivatives fair values can fluctuate
causing actual GAAP earnings to vary accordingly.
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The company's long-term compound annual growth goals on earnings per
share from operations are in the range of 7 to 10 percent.
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The company continually seeks opportunities to expand through organic
growth and strategic acquisitions.
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The company focuses on creating value through vertical integration
between its business units. For example, the pipeline and energy
services business' partially owned diesel topping plant under
construction in the Bakken region will have the construction materials
and services business involved in constructing the facility, the
exploration and production business supplying production, either
directly or in kind, to the plant, the pipeline transporting natural
gas to the plant, and the utility supplying electricity.
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Estimated capital expenditures for 2013 are approximately $820
million, including approximately $30 million in proceeds from the sale
of non-strategic assets at the exploration and production business.
Capital expenditure projections exclude noncontrolling interest
capital expenditures related to Dakota Prairie Refining.
Exploration and Production
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Three Months Ended
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Nine Months Ended
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September 30,
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September 30,
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2013
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2012
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2013
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2012
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(Dollars in millions, where applicable)
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Operating revenues:
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Oil
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$
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121.4
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$
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75.1
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$
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327.3
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$
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217.4
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Natural gas liquids
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7.6
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7.9
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21.3
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24.6
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Natural gas
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20.1
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16.7
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62.5
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48.1
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Realized commodity derivatives gain (loss)
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(6.6
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10.0
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(1.0
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24.6
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Unrealized commodity derivatives loss
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(12.6
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(1.2
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(5.4
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(.5
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129.9
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108.5
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404.7
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314.2
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Operating expenses:
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Operation and maintenance:
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Lease operating costs
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20.6
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20.7
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63.4
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58.2
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Gathering and transportation
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3.5
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4.3
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12.1
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12.8
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Other
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12.5
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9.6
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32.9
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28.4
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Depreciation, depletion and amortization
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49.6
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41.4
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137.8
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112.6
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Taxes, other than income:
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Production and property taxes
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13.3
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9.6
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37.1
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27.8
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Other
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.2
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.2
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.9
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.8
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Write-down of oil and natural gas properties
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—
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160.1
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—
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160.1
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99.7
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245.9
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284.2
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400.7
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Operating income (loss)
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30.2
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(137.4
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120.5
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(86.5
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)
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Earnings (loss)
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$
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17.4
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$
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(87.8
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$
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70.7
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$
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(56.9
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)
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Unrealized commodity derivatives loss
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7.9
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.7
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3.4
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.2
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Write-down of oil and natural gas properties
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—
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100.9
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—
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100.9
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Adjusted earnings
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$
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25.3
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$
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13.8
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$
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74.1
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$
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44.2
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Production:
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Oil (MBbls)
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1,252
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912
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3,571
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2,555
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Natural gas liquids (MBbls)
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196
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211
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588
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610
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Natural gas (MMcf)
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7,302
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7,390
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21,002
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25,676
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Total Production (MBOE)
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2,664
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2,354
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7,659
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7,444
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Average realized prices (excluding realized and unrealized
commodity derivatives gain/loss):
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Oil (per barrel)
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$
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97.00
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$
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82.37
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$
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91.64
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$
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85.09
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Natural gas liquids (per barrel)
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$
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39.02
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$
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37.32
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$
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36.24
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$
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40.32
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Natural gas (per Mcf)
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$
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2.75
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$
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2.25
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$
|
2.98
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$
|
1.88
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Average realized prices (including realized commodity derivatives
gain/loss):
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Oil (per barrel)
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$
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91.03
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$
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85.61
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$
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91.13
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$
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85.69
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Natural gas liquids (per barrel)
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$
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39.02
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$
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37.32
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$
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36.24
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$
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40.32
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Natural gas (per Mcf)
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$
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2.87
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$
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3.20
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$
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3.02
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$
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2.77
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Average depreciation, depletion and amortization rate, per BOE
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$
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17.90
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$
|
16.85
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$
|
17.25
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$
|
14.44
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Production costs, including taxes, per BOE:
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Lease operating costs
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$
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7.74
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$
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8.77
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|
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$
|
8.28
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$
|
7.81
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Gathering and transportation
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1.33
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1.84
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1.58
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|
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1.72
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Production and property taxes
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4.98
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4.07
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|
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4.85
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3.74
|
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|
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$
|
14.05
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|
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$
|
14.68
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|
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$
|
14.71
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$
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13.27
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Notes:
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-- Oil includes crude oil and condensate; natural gas liquids are
reflected separately.
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-- Results are reported in barrel of oil equivalents based on a
6:1 ratio.
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Third quarter adjusted earnings at this segment were $25.3 million in
2013, compared to $13.8 million in 2012. This increase reflects
increased oil production of 37 percent. Higher average realized oil and
natural gas prices were largely offset by a net reduction in realized
commodity derivatives. Partially offsetting the earnings increase were
higher depreciation, depletion and amortization expense and higher
production taxes. GAAP earnings were $17.4 million in third quarter 2013
compared to a loss of $87.8 million in the same period last year.
Effective April 1, the company elected to discontinue hedge accounting
for all of its commodity derivative instruments and, therefore, all
prospective changes in the fair value of the company's commodity
derivative instruments are recorded in the income statement.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
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The company expects to spend approximately $400 million in capital
expenditures in 2013. The 2013 planned capital expenditure total does
not include potential acquisitions nor proceeds from closed
divestitures of non-strategic assets of approximately $30 million.
-
For 2013, the company expects a 30 to 35 percent increase in oil
production. Noting the level of production reported for the fourth
quarter 2012 (59 percent higher than fourth quarter 2011), the company
anticipates fourth quarter 2013 production growth of 10 to 15 percent
over last year.
-
The company expects a slight decrease in natural gas liquids
production and a 15 to 20 percent decrease in natural gas production
for 2013 compared to a year ago. The vast majority of the capital
program is focused on growing oil production considering current
relative commodity prices. The company expects to return to some
natural gas development when the commodity prices make it more
profitable to do so.
-
During the third quarter, the company had a total of four drilling
rigs deployed on its acreage in the Bakken, Paradox and Texas areas.
-
Bakken areas
-
The company owns a total of approximately 127,000 net acres of
leaseholds in Mountrail, Stark and Richland counties.
-
Capital expenditures are expected to total approximately $210
million in 2013. Two rigs are in operation.
-
Net oil production for third quarter was approximately 8,300
barrels of oil per day.
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Paradox Basin, Utah
-
The company has approximately 92,000 net acres and also has an
option to earn another 20,000 acres.
-
Capital expenditures are expected to total $80 million in 2013.
The company is operating one rig in the area and expects to add a
second rig within the next two to three months.
-
Following nine months of flowing at a constant 1,500 BOPD gross,
the Cane Creek Unit 12-1 well came off its plateau rate and is
still flowing at approximately 1,000 BOPD.
-
Net oil production for third quarter was approximately 2,300 BOPD,
up 272 percent from third quarter 2012 and consistent with second
quarter 2013. Well down time, delayed completion activity, and the
CCU 12-1 coming off of plateau limited growth in the third
quarter. Current production is approximately 3,000 BOPD.
-
The latest well completed was the CCU 36-1, which has been flowing
consistently above 1,250 BOPD since Oct. 11 with a flowing
pressure of approximately 3,400 psi.
-
The company's understanding of this play and the quality of the
play continues to improve. Accelerated development of the play
will be largely dependent upon receiving sufficient permits to
sustain a multi-rig program. It is anticipated that this field
will play a key role in the company's oil growth strategy.
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Texas
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The company is targeting areas that have the potential for higher
liquids content with approximately $40 million of capital planned
for this year.
-
Other opportunities
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The remaining forecasted 2013 capital has been allocated to other
operated and non-operated opportunities.
-
Earnings guidance reflects estimated average NYMEX index prices for
November and December in the range of $95 to $105 per barrel of crude
oil, and $3.50 to $4.00 per Mcf of natural gas. Estimated prices for
natural gas liquids are in the range of $35 to $50 per barrel.
-
For the last three months of 2013, the company has derivative
instruments for 11,000 BOPD utilizing swaps and costless collars with
a weighted average price of $97.76 and $92.50/$107.03 (floor/ceiling)
respectively, and 60,000 MMBtu of natural gas per day utilizing swaps
at a weighted average price of $3.80.
-
For the first six months of 2014, the company has derivative
instruments for 11,000 BOPD, and 5,000 BOPD for July through December,
utilizing swaps with a weighted average price of $94.74, and for 2014
the company has derivative instruments for 20,000 MMBtu of natural gas
per day utilizing swaps at a weighted average price of $4.13.
-
For 2015, the company has a derivative instrument for 10,000 MMBtu of
natural gas per day utilizing a swap at $4.2825.
-
The commodity derivative instruments that are in place as of Oct. 31
are summarized in the following chart:
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|
|
|
|
|
|
|
|
|
|
|
|
Forward
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
|
Volume
|
|
|
Price
|
Commodity
|
|
|
Type
|
|
|
Index
|
|
|
Outstanding
|
|
|
(Bbl/MMBtu)
|
|
|
(Per Bbl/MMBtu)
|
Crude Oil
|
|
|
Collar
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$95.00-$117.00
|
Crude Oil
|
|
|
Collar
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$90.00-$97.05
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
46,000
|
|
|
$95.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
46,000
|
|
|
$95.30
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
46,000
|
|
|
$100.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
46,000
|
|
|
$100.02
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$102.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$104.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$98.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
46,000
|
|
|
$94.15
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
46,000
|
|
|
$94.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$97.45
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$94.15
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
92,000
|
|
|
$95.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$95.15
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$95.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$90.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$91.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$92.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$93.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$98.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$99.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 6/14
|
|
|
181,000
|
|
|
$100.07
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 12/14
|
|
|
365,000
|
|
|
$94.05
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 12/14
|
|
|
365,000
|
|
|
$95.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
7/14 - 12/14
|
|
|
184,000
|
|
|
$94.25
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
7/14 - 12/14
|
|
|
184,000
|
|
|
$95.00
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
7/14 - 12/14
|
|
|
184,000
|
|
|
$95.25
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
920,000
|
|
|
$3.76
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
920,000
|
|
|
$3.90
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
920,000
|
|
|
$4.00
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/13
|
|
|
1,840,000
|
|
|
$3.50
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
10/13 - 12/14
|
|
|
4,570,000
|
|
|
$4.13
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/14 - 12/14
|
|
|
3,650,000
|
|
|
$4.13
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/15 - 12/15
|
|
|
3,650,000
|
|
|
$4.2825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
|
|
Electric and Natural Gas Utilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
|
(Dollars in millions, where applicable)
|
Operating revenues
|
|
$
|
68.3
|
|
|
$
|
63.5
|
|
|
$
|
189.9
|
|
|
$
|
174.4
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel and purchased power
|
|
|
20.0
|
|
|
|
17.6
|
|
|
|
59.8
|
|
|
|
51.2
|
|
Operation and maintenance
|
|
|
19.5
|
|
|
|
17.9
|
|
|
|
56.4
|
|
|
|
53.1
|
|
Depreciation, depletion and amortization
|
|
|
8.1
|
|
|
|
8.1
|
|
|
|
24.6
|
|
|
|
24.2
|
|
Taxes, other than income
|
|
|
2.7
|
|
|
|
2.6
|
|
|
|
8.4
|
|
|
|
7.9
|
|
|
|
|
50.3
|
|
|
|
46.2
|
|
|
|
149.2
|
|
|
|
136.4
|
|
Operating income
|
|
|
18.0
|
|
|
|
17.3
|
|
|
|
40.7
|
|
|
|
38.0
|
|
Earnings
|
|
$
|
11.4
|
|
|
$
|
11.0
|
|
|
$
|
25.7
|
|
|
$
|
23.0
|
|
Retail sales (million kWh)
|
|
|
795.2
|
|
|
|
753.8
|
|
|
|
2,329.4
|
|
|
|
2,189.8
|
|
Sales for resale (million kWh)
|
|
|
5.4
|
|
|
|
8.9
|
|
|
|
21.5
|
|
|
|
11.8
|
|
Average cost of fuel and purchased power per kWh
|
|
$
|
.024
|
|
|
$
|
.022
|
|
|
$
|
.024
|
|
|
$
|
.022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
|
(Dollars in millions)
|
Operating revenues
|
|
$
|
77.5
|
|
|
$
|
80.1
|
|
|
$
|
536.8
|
|
|
$
|
504.8
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased natural gas sold
|
|
|
36.5
|
|
|
|
38.0
|
|
|
|
323.5
|
|
|
|
300.2
|
|
Operation and maintenance
|
|
|
35.1
|
|
|
|
31.8
|
|
|
|
104.9
|
|
|
|
102.9
|
|
Depreciation, depletion and amortization
|
|
|
12.7
|
|
|
|
11.4
|
|
|
|
37.3
|
|
|
|
34.0
|
|
Taxes, other than income
|
|
|
7.3
|
|
|
|
7.0
|
|
|
|
32.9
|
|
|
|
33.2
|
|
|
|
|
91.6
|
|
|
|
88.2
|
|
|
|
498.6
|
|
|
|
470.3
|
|
Operating income (loss)
|
|
|
(14.1
|
)
|
|
|
(8.1
|
)
|
|
|
38.2
|
|
|
|
34.5
|
|
Earnings (loss)
|
|
$
|
(11.2
|
)
|
|
$
|
(8.8
|
)
|
|
$
|
15.4
|
|
|
$
|
10.3
|
|
Volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
7.6
|
|
|
|
8.0
|
|
|
|
67.7
|
|
|
|
60.1
|
|
Transportation
|
|
|
37.0
|
|
|
|
30.0
|
|
|
|
105.6
|
|
|
|
94.7
|
|
Total throughput
|
|
|
44.6
|
|
|
|
38.0
|
|
|
|
173.3
|
|
|
|
154.8
|
|
Degree days (% of normal)*
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota/Great Plains
|
|
|
34
|
%
|
|
|
38
|
%
|
|
|
101
|
%
|
|
|
75
|
%
|
Cascade
|
|
|
74
|
%
|
|
|
91
|
%
|
|
|
92
|
%
|
|
|
98
|
%
|
Intermountain
|
|
|
89
|
%
|
|
|
51
|
%
|
|
|
109
|
%
|
|
|
92
|
%
|
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
|
|
|
|
|
The combined utility businesses reported earnings of $200,000 in the
third quarter of 2013, compared to earnings of $2.2 million for the same
period in 2012. This decrease in earnings reflects higher operation and
maintenance expense, largely payroll-related, as well as higher
depreciation, depletion and amortization expense. Partially offsetting
the decrease was higher electric retail sales margins, largely the
result of 5 percent higher volumes.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
The company filed an application Sept. 18 with the North Dakota Public
Service Commission for a natural gas rate increase requesting a total
of $6.8 million annually or approximately 6.4 percent above current
rates. The case includes the costs associated with the increased
investment in facilities, including ongoing investment in new and
replacement distribution facilities, an operations building, automated
meter reading and a new customer billing system. The company requested
an interim increase, subject to refund, of $4.5 million or
approximately 4.2 percent. On Oct. 23, a settlement agreement was
filed reflecting an increase of $4.3 million annually or approximately
4 percent including interim rates in the same amount to be effective
with service rendered beginning Nov. 17. An informal hearing is
scheduled for Nov. 13.
-
The company filed an application June 14 for an advance determination
of prudence with NDPSC to add pollution control equipment at the Lewis
& Clark generating station projected to be completed in 2016 to comply
with the Mercury and Air Toxics Standards rules. On Oct. 9, the
commission issued an order approving the ADP. Project cost is
estimated to be $27.7 million.
-
The company filed an application Feb. 11 with NDPSC for approval of an
environmental cost recovery rider related to ongoing construction
costs at the Big Stone Station for the installation of the
best-available retrofit technology air-quality control system. A
hearing was held Sept. 16. The company's share of the cost for the
installation is estimated at $100 million and is expected to be
complete in 2015. The commission has approved advance determination of
prudence for recovery of costs.
-
The company filed an application Dec. 21 with the South Dakota Public
Utilities Commission for a natural gas rate increase requesting a
total of $1.5 million annually or approximately 3.3 percent above
current rates. The case includes the costs associated with the
increased investment in facilities, including ongoing investment in
new and replacement distribution facilities, an operations building,
automated meter reading and new customer billing system. The company
implemented the full request July 22, subject to refund. On Oct. 24, a
settlement stipulation was filed reflecting a rate increase of
$900,000 annually, or approximately 2 percent, which was approved by
the commission at a hearing held today. The new rates will be
effective Dec. 1.
-
The company filed an application Sept. 26, 2012, with the Montana
Public Service Commission for a natural gas rate increase requesting a
total of $3.5 million annually or approximately 5.9 percent above
current rates. The case includes the costs associated with the
increased investment in facilities, including ongoing investment in
new and replacement distribution facilities, a region operations
building, automated meter reading and new customer billing system. The
company requested an interim increase of $1.7 million or approximately
2.9 percent. The commission granted an interim increase of
approximately $850,000 annually, effective April 15. A hearing was
held Aug. 5 and 6.
-
The company is constructing an 88-megawatt simple-cycle natural gas
turbine and associated facilities, with an estimated project cost of
$77 million and a projected in-service date in third quarter 2014. It
is located on owned property adjacent to the company's Heskett
Generating Station near Mandan, N.D. The capacity is necessary to meet
the requirements of the company's integrated electric system customers
and will be a partial replacement for third-party contract capacity
expiring in 2015. Advance determination of prudence and a Certificate
of Public Convenience and Necessity have been received from the NDPSC.
-
Investments are being made in 2013 totaling approximately $70 million
to serve the growing electric and natural gas customer base associated
with the Bakken oil development where customer growth is substantially
higher than the national average.
-
Rate base growth is projected to be approximately 6 percent compounded
annually over the next five years, including plans for an approximate
$1 billion capital investment program.
-
The company is analyzing potential projects for accommodating load
growth in its industrial and agricultural sectors, with company- and
customer-owned pipeline facilities designed to serve existing
facilities served by fuel oil or propane, and to serve new customers.
The company is engaged on a 30-mile, $62 million, natural gas line
project into the Hanford Nuclear Site in Washington.
-
The company along with a partner expects to build a 345kv transmission
line from Ellendale, N.D., to Big Stone City, S.D., about 160 miles,
at a total cost of approximately $360 million. The company's share
would be one-half. The project is a Midwest Independent Transmission
System Operator multi-value project. A route application was filed in
August with the state of South Dakota, and in October with the state
of North Dakota. The project is expected to be complete in 2019.
-
The company is involved with a number of pipeline projects to enhance
the reliability and deliverability of its system in the Pacific
Northwest and Idaho.
Pipeline and Energy Services
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
September 30,
|
|
|
|
|
2013
|
|
2012
|
|
2013
|
|
|
2012
|
|
|
|
|
(Dollars in millions)
|
|
Operating revenues
|
|
$
|
51.3
|
|
$
|
48.3
|
|
$
|
148.6
|
|
|
|
$
|
141.6
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Purchased natural gas sold
|
|
14.0
|
|
10.8
|
|
42.6
|
|
|
|
35.4
|
|
|
|
Operation and maintenance
|
|
16.1
|
|
19.2
|
|
65.3
|
|
*
|
|
34.8
|
|
**
|
|
Depreciation, depletion and amortization
|
|
7.1
|
|
7.3
|
|
22.0
|
|
|
|
20.4
|
|
|
|
Taxes, other than income
|
|
3.3
|
|
3.5
|
|
10.3
|
|
|
|
10.5
|
|
|
|
|
|
40.5
|
|
40.8
|
|
140.2
|
|
|
|
101.1
|
|
|
Operating income
|
|
10.8
|
|
7.5
|
|
8.4
|
|
|
|
40.5
|
|
|
Earnings
|
|
$
|
5.3
|
|
$
|
3.3
|
|
$
|
1.3
|
|
*
|
|
$
|
21.9
|
|
**
|
|
Natural gas gathering asset impairment
|
|
—
|
|
—
|
|
9.0
|
|
|
|
1.7
|
|
|
|
Net benefit related to natural gas gathering operations litigation
|
|
—
|
|
—
|
|
—
|
|
|
|
(15.0
|
)
|
|
Adjusted earnings
|
|
$
|
5.3
|
|
$
|
3.3
|
|
$
|
10.3
|
|
|
|
$
|
8.6
|
|
|
Transportation volumes (MMdk)
|
|
52.1
|
|
34.1
|
|
129.2
|
|
|
|
103.0
|
|
|
Natural gas gathering volumes (MMdk)
|
|
10.6
|
|
10.7
|
|
30.5
|
|
|
|
36.5
|
|
|
Customer natural gas storage balance (MMdk):
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
25.2
|
|
40.4
|
|
43.7
|
|
|
|
36.0
|
|
|
|
Net injection (withdrawal)
|
|
12.9
|
|
8.8
|
|
(5.6
|
)
|
|
|
13.2
|
|
|
|
End of period
|
|
38.1
|
|
49.2
|
|
38.1
|
|
|
|
49.2
|
|
|
*
|
Reflects an impairment of coalbed natural gas gathering assets of
$14.5 million ($9.0 million after tax).
|
**
|
Reflects a net benefit of $24.1 million ($15.0 million after tax)
related to natural gas gathering operations litigation, largely
reflected in operation and maintenance expense, as well as an
impairment of coalbed natural gas gathering assets of $2.7 million
($1.7 million after tax).
|
This segment reported third quarter earnings of $5.3 million, compared
to $3.3 million in 2012. The company saw higher earnings from its
interest in the Pronghorn natural gas and oil midstream assets,
primarily from higher volumes. Also contributing were lower operation
and maintenance expense, largely lower payroll-related, contract
services and legal, as well as higher transportation volumes. Partially
offsetting these increases was lower storage services revenue.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
The company, in conjunction with Calumet Specialty Products Partners,
L.P., formed Dakota Prairie Refining, LLC, to develop, build and
operate a 20,000-barrel-per-day diesel topping plant in southwestern
North Dakota. Construction began on the facility in late March
and, when complete, it will process Bakken crude into diesel, which
will be marketed within the Bakken region. Total project costs are
estimated to be approximately $300 million, with a projected
in-service date in late 2014. EBITDA for the first year of operation
is projected to be in the range of $70 million to $90 million, to be
shared equally with Calumet.
-
In May 2012 the company purchased a 50 percent undivided interest in
Whiting Oil and Gas Corp.'s Pronghorn natural gas and oil midstream
assets near Belfield, N.D., in the Bakken area. The company invested
approximately $100 million in 2012 including the purchase price. The
Belfield natural gas processing plant has an inlet processing capacity
of 35 million cubic feet per day. The company will receive a full year
of benefit from this acquisition in 2013.
-
The company is engaged in various natural gas pipeline projects to be
constructed in 2014. Namely connections for the planned Garden Creek
II natural gas processing plant in the Bakken, an expansion of its
transmission system to increase capacity to the Black Hills, and a
24-mile pipeline and related processing facilities to transport
Fidelity's Paradox Basin natural gas production. The total cost for
these projects is approximately $53 million.
-
In May, the company announced plans for a proposed 400-mile natural
gas pipeline from western North Dakota to western Minnesota to
transport natural gas to markets in eastern North Dakota, Minnesota
and Wisconsin. The company is evaluating alternate routes that would
terminate further north, providing customers with access to additional
markets via interconnections with Great Lakes Gas Transmission,
TransCanada and Viking Gas Transmission in northwest Minnesota. The
pipeline initially would transport approximately 400 MMcf per day of
natural gas and could be expanded to more than 500 MMcf per day. The
project investment is estimated to be $650 million to $700 million.
Following an open season and receipt of adequate capacity commitments
and necessary permits and regulatory approvals, construction on the
new pipeline would begin as early as 2016.
-
On Oct. 31, WBI Energy Transmission filed a Section 4 rate case with
the FERC, the first case it has filed in approximately 14 years. An
increase in investments of $312 million and increased operating costs
since 1999, combined with reduced storage and off system volumes
because of narrowed basis and seasonal price spreads, which have
resulted from shale gas developments in the United States, are the
drivers for the requested rate increase of $28.9 million annually. The
proposed effective date of the rates is Dec. 1.
-
The company continues to pursue expansion of facilities and services
offered to customers. Energy development within its geographic region
is expanding, most notably in the Bakken area, where the company owns
an extensive natural gas pipeline system. Ongoing energy development
is expected to continue to provide growth opportunities for this
business.
Construction
|
|
|
|
|
|
Construction Materials and Contracting
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(Dollars in millions)
|
Operating revenues
|
|
$
|
714.4
|
|
$
|
650.0
|
|
$
|
1,312.0
|
|
$
|
1,241.5
|
Operating expenses:
|
|
|
|
|
|
|
Operation and maintenance
|
|
600.9
|
|
549.6
|
|
1,148.8
|
|
1,103.3
|
Depreciation, depletion and amortization
|
|
19.0
|
|
20.3
|
|
56.7
|
|
59.9
|
Taxes, other than income
|
|
11.6
|
|
11.0
|
|
30.7
|
|
29.6
|
|
|
631.5
|
|
580.9
|
|
1,236.2
|
|
1,192.8
|
Operating income
|
|
82.9
|
|
69.1
|
|
75.8
|
|
48.7
|
Earnings
|
|
$
|
49.2
|
|
$
|
41.9
|
|
$
|
38.6
|
|
$
|
24.7
|
Sales (000's):
|
|
|
|
|
|
|
Aggregates (tons)
|
|
9,902
|
|
9,009
|
|
19,012
|
|
17,983
|
Asphalt (tons)
|
|
3,311
|
|
3,013
|
|
4,978
|
|
4,874
|
Ready-mixed concrete (cubic yards)
|
|
1,132
|
|
1,105
|
|
2,458
|
|
2,410
|
|
|
|
|
|
|
Construction Services
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In millions)
|
Operating revenues
|
|
$
|
270.1
|
|
$
|
247.2
|
|
$
|
781.1
|
|
$
|
689.4
|
Operating expenses:
|
|
|
|
|
|
|
Operation and maintenance
|
|
238.8
|
|
219.9
|
|
683.2
|
|
606.5
|
Depreciation, depletion and amortization
|
|
3.0
|
|
2.8
|
|
8.9
|
|
8.3
|
Taxes, other than income
|
|
7.3
|
|
7.2
|
|
25.3
|
|
22.1
|
|
|
249.1
|
|
229.9
|
|
717.4
|
|
636.9
|
Operating income
|
|
21.0
|
|
17.3
|
|
63.7
|
|
52.5
|
Earnings
|
|
$
|
12.2
|
|
$
|
9.9
|
|
$
|
36.7
|
|
$
|
30.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The combined construction businesses reported third quarter earnings of
$61.4 million, compared to earnings of $51.8 million a year ago. The
earnings increase reflects higher equipment sales and rental margins and
higher workloads and margins in the Central and Western regions at the
services group, and higher aggregate and asphalt margins and volumes at
the materials group. On a combined basis, partially offsetting the
earnings increase was higher selling, general and administrative
expenses.
The following information highlights the key growth strategies,
projections and certain assumptions for the construction segments:
-
The construction materials approximate work backlog as of Sept. 30 was
$525 million, compared to $464 million a year ago. Private work
represents 13 percent of construction backlog and public work
represents 87 percent of backlog. The Sept. 30 approximate backlog at
construction services was $433 million, compared to $370 million a
year ago. The backlogs include a variety of projects such as highway
paving projects, airports, bridge work, reclamation, harbor
expansions, substation and line construction, solar and other
commercial, institutional and industrial projects including refinery
work.
-
The company's approximate backlog in North Dakota as of Sept. 30 was
$157 million, including a $55 million North Dakota highway
construction contract, the largest contract in the company's history.
North Dakota backlog was $65 million a year ago.
-
Projected revenues included in the company's 2013 earnings guidance
are in the range of $1.6 billion to $1.7 billion for construction
materials and $1.0 billion to $1.1 billion for construction services.
-
The company anticipates margins in 2013 to be higher than 2012.
-
The company continues to pursue opportunities for expansion in energy
projects such as refineries, transmission, substations, utility
services, solar, wind towers and geothermal. Initiatives are aimed at
capturing additional market share and expanding into new markets.
-
As the country's sixth-largest sand and gravel producer, the company
will continue to strategically manage its 1.1 billion tons of
aggregate reserves in all its markets, as well as take further
advantage of being vertically integrated.
Other
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In millions)
|
Operating revenues
|
|
$
|
2.3
|
|
|
$
|
2.3
|
|
|
$
|
6.8
|
|
|
$
|
7.0
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
(1.4
|
)
|
|
1.5
|
|
|
1.2
|
|
|
4.4
|
Depreciation, depletion and amortization
|
|
.5
|
|
|
.5
|
|
|
1.5
|
|
|
1.5
|
Taxes, other than income
|
|
.1
|
|
|
—
|
|
|
.2
|
|
|
.1
|
|
|
(.8
|
)
|
|
2.0
|
|
|
2.9
|
|
|
6.0
|
Operating income
|
|
3.1
|
|
|
.3
|
|
|
3.9
|
|
|
1.0
|
Income from continuing operations
|
|
1.3
|
|
|
.8
|
|
|
2.1
|
|
|
1.9
|
Income (loss) from discontinued operations, net of tax
|
|
(.1
|
)
|
|
(.1
|
)
|
|
(.2
|
)
|
|
4.8
|
Earnings
|
|
$
|
1.2
|
|
|
$
|
.7
|
|
|
$
|
1.9
|
|
|
$
|
6.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
This segment reported third quarter earnings of $1.2 million, compared
to earnings of $700,000 a year ago. The earnings increase resulted from
lower insurance costs, partially offset by lower earnings from equity
method investments.
Use of Non-GAAP Financial Measures
The company, in addition
to presenting its earnings information in conformity with Generally
Accepted Accounting Principles (GAAP), has provided non-GAAP earnings
data that reflect adjustments to exclude:
Three Months Ended September 30, 2013 and 2012:
-
A write-down of oil and natural gas properties of $100.9 million after
tax in 2012.
-
An unrealized commodity derivatives loss of $7.9 million after tax in
2013, and $700,000 after tax in 2012.
Nine Months Ended September 30, 2013 and 2012:
-
A write-down of oil and natural gas properties of $100.9 million after
tax in 2012.
-
A reversal of an arbitration charge of $15.0 million after tax in 2012.
-
Natural gas gathering asset impairments of $9.0 million after tax in
2013, and $1.7 million after tax in 2012.
-
An unrealized commodity derivatives loss of $3.4 million after tax in
2013, and $200,000 after tax in 2012.
Twelve Months Ended September 30, 2013 and 2012:
-
Write-downs of oil and natural gas properties of $145.9 million after
tax in 2013, and $100.9 million after tax in 2012.
-
A reversal of an arbitration charge of $15.0 million after tax in 2012.
-
Natural gas gathering asset impairments of $9.0 million after tax in
2013, and $1.7 million after tax in 2012.
-
An unrealized commodity derivatives loss of $3.5 million after tax in
2013, and an unrealized commodity derivatives gain of $800,000 after
tax in 2012.
The company believes that these non-GAAP financial measures are useful
to investors because the items excluded are not indicative of the
company's continuing operating results. Also, the company's management
uses these non-GAAP financial measures as indicators for planning and
forecasting future periods. The presentation of this additional
information is not meant to be considered a substitute for financial
measures prepared in accordance with GAAP.
Risk Factors and Cautionary Statements that May Affect Future Results
The
information in this release includes certain forward-looking statements,
including earnings per share guidance and statements by the president
and CEO of MDU Resources, within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although the company believes that its
expectations are based on reasonable assumptions, actual results may
differ materially. Following are important factors that could cause
actual results or outcomes for the company to differ materially from
those discussed in forward-looking statements.
-
The company’s exploration and production and pipeline and energy
services businesses are dependent on factors, including commodity
prices and commodity price basis differentials, that are subject to
various external influences that cannot be controlled.
-
The regulatory approval, permitting, construction, startup and/or
operation of power generation facilities and Dakota Prairie Refinery
may involve unanticipated events or delays that could negatively
impact the company’s business and its results of operations and cash
flows.
-
Economic volatility affects the company’s operations, as well as the
demand for its products and services and the value of its investments
and investment returns including its pension and other postretirement
benefit plans, and may have a negative impact on the company’s future
revenues and cash flows.
-
The company relies on financing sources and capital markets. Access to
these markets may be adversely affected by factors beyond the
company’s control. If the company is unable to obtain economic
financing in the future, the company’s ability to execute its business
plans, make capital expenditures or pursue acquisitions that the
company may otherwise rely on for future growth could be impaired. As
a result, the market value of the company’s common stock may be
adversely affected. If the company issues a substantial amount of
common stock it could have a dilutive effect on its existing
shareholders.
-
The company is exposed to credit risk and the risk of loss resulting
from the nonpayment and/or nonperformance by the company’s customers
and counterparties.
-
The backlogs at the company’s construction materials and contracting
and construction services businesses are subject to delay or
cancellation and may not be realized.
-
Actual quantities of recoverable oil, natural gas liquids and natural
gas reserves and discounted future net cash flows from those reserves
may vary significantly from estimated amounts. There is a risk that
changes in estimates of proved reserve quantities or other factors
including downward movements in prices, could result in additional
future noncash write-downs of the company's oil and natural gas
properties.
-
The company’s operations are subject to environmental laws and
regulations that may increase costs of operations, impact or limit
business plans, or expose the company to environmental liabilities.
-
Initiatives to reduce greenhouse gas emissions could adversely impact
the company’s operations.
-
The company is subject to government regulations that may delay and/or
have a negative impact on its business and its results of operations
and cash flows. Statutory and regulatory requirements also may limit
another party’s ability to acquire the company.
-
Weather conditions can adversely affect the company’s operations,
revenues and cash flows.
-
Competition is increasing in all of the company’s businesses.
-
The company could be subject to limitations on its ability to pay
dividends.
-
An increase in costs related to obligations under multiemployer
pension plans could have a material negative effect on the company’s
results of operations and cash flows.
-
The company's operations may be negatively impacted by cyber attacks
or acts of terrorism.
-
Other factors that could cause actual results or outcomes for the
company to differ materially from those discussed in forward-looking
statements include:
-
Acquisition, disposal and impairments of assets or facilities.
-
Changes in operation, performance and construction of plant
facilities or other assets.
-
Changes in present or prospective generation.
-
The ability to obtain adequate and timely cost recovery for the
company’s regulated operations through regulatory proceedings.
-
The availability of economic expansion or development
opportunities.
-
Population growth rates and demographic patterns.
-
Market demand for, available supplies of, and/or costs of, energy-
and construction-related products and services.
-
The cyclical nature of large construction projects at certain
operations.
-
Changes in tax rates or policies.
-
Unanticipated project delays or changes in project costs,
including related energy costs.
-
Unanticipated changes in operating expenses or capital
expenditures.
-
Labor negotiations or disputes.
-
Inability of the various contract counterparties to meet their
contractual obligations.
-
Changes in accounting principles and/or the application of such
principles to the company.
-
Changes in technology.
-
Changes in legal or regulatory proceedings.
-
The ability to effectively integrate the operations and the
internal controls of acquired companies.
-
The ability to attract and retain skilled labor and key personnel.
-
Increases in employee and retiree benefit costs and funding
requirements.
For a further discussion of these risk factors and cautionary
statements, refer to Item 1A – Risk Factors in the company’s most recent
Form 10-K and Form 10-Q.
MDU Resources Group, Inc.
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
September 30,
|
|
September 30,
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
|
(In millions, except per share amounts)
|
|
|
(Unaudited)
|
Operating revenues
|
|
$
|
1,285.8
|
|
|
$
|
1,173.5
|
|
|
$
|
3,278.0
|
|
|
$
|
2,994.3
|
Operating expenses:
|
|
|
|
|
|
|
|
|
Fuel and purchased power
|
|
20.0
|
|
|
17.6
|
|
|
59.8
|
|
|
51.2
|
Purchased natural gas sold
|
|
35.8
|
|
|
35.2
|
|
|
305.3
|
|
|
279.1
|
Operation and maintenance
|
|
934.3
|
|
|
861.7
|
|
|
2,132.5
|
|
|
1,982.3
|
Depreciation, depletion and amortization
|
|
100.0
|
|
|
91.8
|
|
|
288.8
|
|
|
260.9
|
Taxes, other than income
|
|
45.8
|
|
|
41.1
|
|
|
145.8
|
|
|
132.0
|
Write-down of oil and natural gas properties
|
|
—
|
|
|
160.1
|
|
|
—
|
|
|
160.1
|
|
|
1,135.9
|
|
|
1,207.5
|
|
|
2,932.2
|
|
|
2,865.6
|
Operating income (loss)
|
|
149.9
|
|
|
(34.0
|
)
|
|
345.8
|
|
|
128.7
|
Earnings (loss) from equity method investments
|
|
(.1
|
)
|
|
2.4
|
|
|
(.4
|
)
|
|
4.0
|
Other income
|
|
2.3
|
|
|
1.7
|
|
|
5.0
|
|
|
4.1
|
Interest expense
|
|
21.0
|
|
|
19.9
|
|
|
63.3
|
|
|
56.9
|
Income (loss) before income taxes
|
|
131.1
|
|
|
(49.8
|
)
|
|
287.1
|
|
|
79.9
|
Income taxes
|
|
46.5
|
|
|
(20.3
|
)
|
|
99.6
|
|
|
24.5
|
Income (loss) from continuing operations
|
|
84.6
|
|
|
(29.5
|
)
|
|
187.5
|
|
|
55.4
|
Income (loss) from discontinued operations, net of tax
|
|
(.1
|
)
|
|
(.1
|
)
|
|
(.2
|
)
|
|
4.8
|
Net income (loss)
|
|
84.5
|
|
|
(29.6
|
)
|
|
187.3
|
|
|
60.2
|
Net loss attributable to noncontrolling interest
|
|
—
|
|
|
—
|
|
|
(.2
|
)
|
|
—
|
Dividends declared on preferred stocks
|
|
.2
|
|
|
.2
|
|
|
.5
|
|
|
.5
|
Earnings (loss) on common stock
|
|
$
|
84.3
|
|
|
$
|
(29.8
|
)
|
|
$
|
187.0
|
|
|
$
|
59.7
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share – basic:
|
|
|
|
|
|
|
|
|
Earnings (loss) before discontinued operations
|
|
$
|
.45
|
|
|
$
|
(.16
|
)
|
|
$
|
.99
|
|
|
$
|
.29
|
Discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
—
|
|
|
.03
|
Earnings (loss) per common share – basic
|
|
$
|
.45
|
|
|
$
|
(.16
|
)
|
|
$
|
.99
|
|
|
$
|
.32
|
Earnings (loss) per common share – diluted:
|
|
|
|
|
|
|
|
|
Earnings (loss) before discontinued operations
|
|
$
|
.44
|
|
|
$
|
(.16
|
)
|
|
$
|
.99
|
|
|
$
|
.29
|
Discontinued operations, net of tax
|
|
—
|
|
|
—
|
|
|
—
|
|
|
.03
|
Earnings (loss) per common share – diluted
|
|
$
|
.44
|
|
|
$
|
(.16
|
)
|
|
$
|
.99
|
|
|
$
|
.32
|
Dividends declared per common share
|
|
$
|
.1725
|
|
|
$
|
.1675
|
|
|
$
|
.5175
|
|
|
$
|
.5025
|
Weighted average common shares outstanding – basic
|
|
188.8
|
|
|
188.8
|
|
|
188.8
|
|
|
188.8
|
Weighted average common shares outstanding – diluted
|
|
189.6
|
|
|
188.8
|
|
|
189.6
|
|
|
189.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
|
|
|
2013
|
|
|
2012
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data
|
|
|
|
|
|
|
|
|
Book value per common share
|
|
|
$
|
14.49
|
|
|
|
$
|
14.45
|
|
Market price per common share
|
|
|
$
|
27.97
|
|
|
|
$
|
22.04
|
|
Dividend yield (indicated annual rate)
|
|
|
2.5
|
%
|
|
|
3.0
|
%
|
Price/adjusted earnings ratio*
|
|
|
19.3
|
x
|
|
|
19.3
|
x
|
Market value as a percent of book value
|
|
|
193.0
|
%
|
|
|
152.5
|
%
|
Net operating cash flow**
|
|
|
$
|
429
|
|
|
|
$
|
329
|
|
Total assets**
|
|
|
$
|
7,167
|
|
|
|
$
|
6,903
|
|
Total equity**
|
|
|
$
|
2,750
|
|
|
|
$
|
2,743
|
|
Total debt **
|
|
|
$
|
2,019
|
|
|
|
$
|
1,754
|
|
Capitalization ratios:
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
58
|
%
|
|
|
61
|
%
|
|
Total debt
|
|
|
42
|
|
|
|
39
|
|
|
|
|
|
100
|
%
|
|
|
100
|
%
|
*
|
Represents 12 months ended. On a GAAP earnings basis, the ratio is
not meaningful.
|
|
|
|
|
|
|
|
|
**
|
In millions
|
|
|
|
|
|
|
|
|
Copyright Business Wire 2013