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Published: August 01, 2011
MDU Resources Reports Second Quarter Earnings, Reaffirms 2011 Earnings Guidance
BISMARCK, N.D. - (BUSINESS WIRE) - MDU Resources Group, Inc. (NYSE:MDU) today reported second quarter
consolidated earnings of $44.9 million, or 24 cents per common share,
compared to $48.8 million, or 26 cents per common share for the second
quarter of 2010.
"We are pleased with our performance in light of difficult weather that
has impacted many of our operations this year," said Terry D. Hildestad,
president and chief executive officer of MDU Resources. "Our employees
have done an outstanding job of restoring normal operations as quickly
as possible, and we are reaffirming our annual earnings guidance of
$1.05 to $1.30 per share."
The company's exploration and production business, Fidelity, reported
second quarter earnings of $21.3 million compared to $24.0 million in
the same period last year. Average realized natural gas prices declined
9 percent from a year ago, and lower natural gas production as the
company shifts its focus to oil, contributed to the decline. Oil
production was essentially flat from a year ago, in large part the
result of weather that impacted producers throughout North Dakota's
Bakken region.
"In spite of the weather effects, our Bakken oil production still
increased 10 percent over last year and Fidelity's multi-year
development program is under way," Hildestad said. "We have added a
second rig working in the Bakken and have plans to add rigs as we
continue to expand in this area. We recently acquired an additional
20,000 acres of Bakken leaseholds, boosting our total to approximately
90,000 net acres of leaseholds in this major oil play. Despite the
recent delays, we still expect to invest $2.1 billion in this business
over the next five years, including approximately $300 million this
year."
The company saw favorable results on recently completed Bakken wells in
Mountrail County. The Hill 31-30H had a 5-day initial production rate of
1,633 gross barrels of oil equivalents per day. The 30-day IP rate for
the Behr 16-21H was 1,216 gross barrels of oil equivalents per day. Both
wells were completed with 30 frac stages. The company's working interest
in these wells is 38.5 percent and 25.5 percent, respectively.
The pipeline and energy services business continues to pursue expansion
opportunities largely led by forecasted strong growth in natural gas
production in the Bakken area. Construction of compressor facilities to
expand firm capacity out of the area and construction of a pipeline to
move associated gas from a new processing facility are both underway. In
addition, an agreement has been reached to construct another processing
facility takeaway pipeline in 2012.
This business reported earnings of $4.8 million compared with
$9.5 million in the second quarter of 2010 primarily the result of
narrow seasonal basis differentials resulting in lower storage related
activity.
Earnings at the company's utility operations increased to $6.7 million
compared to $5.1 million in the second quarter of 2010. Retail natural
gas sales volumes increased 11 percent as a result of cold spring
weather across the northwestern U.S. The utility also benefited from
interim electric rate increases in North Dakota that went into effect in
mid-June 2010 and Montana effective in February. The North Dakota rate
case recently concluded with the Public Service Commission approval of a
$7.6 million annual increase and the Montana Commission has approved a
settlement agreement for an increase of $2.6 million annually.
The utility recently announced that it has asked the North Dakota
Commission for an advance determination of prudence to build, own and
operate an 88-megawatt natural gas generating facility near Mandan,
North Dakota. If approved, the $85.6 million project is expected to be
in operation by the first quarter of 2015.
Hildestad added, "Our continued strategy of growing our regulated
business has produced results. Our utility had record earnings of
$74 million on a 12-month basis ending June 30."
The company's construction businesses are beginning to see a slight
improvement in the economy. However, the construction materials and
contracting segment was impacted by a wet spring, which delayed the
start of the construction season. The segment reported second quarter
earnings of $5.0 million, compared to $5.7 million in the same period
last year.
Earnings at the Construction Services Group increased to $6.1 million
compared to $2.9 million in the second quarter of 2010, driven by strong
increases in construction workloads and margins in the Western region.
The business also continued to experience strong equipment and
electrical supply sales.
The company will host a webcast at 11 a.m. EDT on Tuesday, Aug. 2 to
discuss earnings results and guidance. The event can be accessed at www.mdu.com.
A webcast replay and audio replay will be available. The dial-in number
for audio replay is (800) 642-1687 or for international callers,
(706) 645-9291, conference ID 73996248.
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 businesses, an exploration and production company and
construction companies. MDU Resources includes regulated electric and
natural gas utilities and regulated natural gas pipelines and energy
services, natural gas and oil production, construction materials and
contracting, and construction services. For more information about MDU
Resources, see the company's Web site 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.
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Earnings
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Earnings
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Second Quarter
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Second Quarter
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2011
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2010
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Business Line
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(In Millions)
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(In Millions)
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Exploration and Production
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Natural gas and oil production
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$
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21.3
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$
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24.0
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Regulated
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Pipeline and energy services
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4.8
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9.5
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Electric and natural gas utilities
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6.7
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5.1
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Construction
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Construction materials and contracting
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5.0
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5.7
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Construction services
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6.1
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2.9
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Other
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1.1
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1.6
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Earnings before discontinued operations
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45.0
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48.8
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Loss from discontinued operations, net of tax
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(.1
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)
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---
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Earnings on common stock
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$
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44.9
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$
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48.8
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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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Earnings per common share for 2011, diluted, are projected in the
range of $1.05 to $1.30. The company expects the approximate
percentage of 2011 earnings per common share by quarter to be:
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Third quarter - 30 percent
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Fourth quarter - 30 percent
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Although near term market conditions are uncertain, the company's
long-term compound annual growth goals on earnings per share from
operations are in the range of 7 percent to 10 percent.
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The company continually seeks opportunities to expand through
strategic acquisitions and organic growth opportunities.
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Estimated capital expenditures for 2011 are approximately
$570 million. The company expects the 2011 estimated capital
expenditures to be funded in its entirety with cash flow generated
from operations.
Exploration and Production
Natural Gas and Oil Production
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Three Months Ended
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Six Months Ended
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June 30,
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June 30,
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2011
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2010
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2011
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2010
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(Dollars in millions, where applicable)
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Operating revenues:
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Natural gas
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$
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44.3
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$
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55.2
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$
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89.7
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$
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112.8
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Oil
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68.5
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55.6
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127.0
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105.6
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112.8
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110.8
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216.7
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218.4
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Operating expenses:
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Operation and maintenance:
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Lease operating costs
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18.4
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16.3
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36.4
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32.1
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Gathering and transportation
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5.6
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5.9
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11.3
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11.8
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Other
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9.2
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8.8
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17.5
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17.4
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Depreciation, depletion and amortization
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33.4
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32.5
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67.6
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62.1
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Taxes, other than income:
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Production and property taxes
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10.5
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9.0
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20.5
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18.5
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Other
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.2
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.1
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.5
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.5
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77.3
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72.6
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153.8
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142.4
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Operating income
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35.5
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38.2
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62.9
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76.0
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Earnings
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$
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21.3
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$
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24.0
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$
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37.6
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$
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46.3
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Production:
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Natural gas (MMcf)
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11,253
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12,809
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23,011
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25,052
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Oil (MBbls)
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821
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831
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1,623
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1,592
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Total Production (MMcfe)
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16,180
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17,794
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32,750
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34,602
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Average realized prices (including
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hedges):
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Natural gas (per Mcf)
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$
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3.94
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$
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4.31
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$
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3.90
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$
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4.50
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Oil (per barrel)
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$
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83.42
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$
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66.88
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$
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78.26
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$
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66.36
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Average realized prices (excluding
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hedges):
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Natural gas (per Mcf)
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$
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3.49
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$
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3.30
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$
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3.44
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$
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3.92
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Oil (per barrel)
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$
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89.25
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$
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67.21
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$
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84.31
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$
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66.83
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Average depreciation, depletion and
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amortization rate, per equivalent
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Mcf
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$
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1.96
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$
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1.74
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$
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1.96
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$
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1.71
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Production costs, including taxes, per
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equivalent Mcf:
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Lease operating costs
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$
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1.14
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$
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.91
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$
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1.11
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$
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.93
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Gathering and transportation
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.34
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.33
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.34
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.34
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Production and property taxes
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.65
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.51
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.63
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.53
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$
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2.13
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$
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1.75
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$
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2.08
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$
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1.80
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The natural gas and oil production segment reported quarterly earnings
of $21.3 million, compared to $24.0 million in 2010. Earnings reflect
decreased natural gas production of 12 percent, lower average realized
natural gas prices of 9 percent and increased lease operating costs.
These decreases were partially offset by 25 percent higher average
realized oil prices.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
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Capital expenditures in 2011 are expected to be approximately
$300 million. The company continues its focus on returns by allocating
a growing portion of its capital investment into the production of oil
in the current commodity price environment. Its capital program
reflects further exploitation of existing properties, acquisition of
additional leasehold acreage, and exploratory drilling. The 2011
planned capital expenditure total does not include potential
acquisitions of producing properties.
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For 2011, the company expects a 1 percent to 5 percent increase in oil
production offset by an 8 percent to 12 percent decrease in natural
gas production, the result of extensive rain and flooding conditions
that hampered operations in the Rocky Mountain region, as well as the
deferral of some gas development activity because of sustained low
natural gas prices. If natural gas prices recover, the company
believes it is positioned to spend additional capital on drilling its
low cost natural gas properties.
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The company added a second drilling rig in the Bakken early in the
second quarter.
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Bakken - Mountrail County, North Dakota
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The company owns approximately 16,000 net acres of leaseholds
targeting the middle Bakken and Three Forks formations. The
drilling of 15 operated and participation in various non-operated
wells is planned for 2011 with approximately $55 million of
capital expenditures. Plans include drilling 17 wells or more
annually in 2012 and 2013.
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Over 50 future wells sites have been identified. Estimated gross
ultimate recovery per well is 250,000 to 500,000 Bbls.
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Bakken - Stark County, North Dakota
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The company holds approximately 50,000 net exploratory leasehold
acres, targeting the Three Forks formation. It anticipates
drilling 3 operated wells on this acreage and participating in
various non-operated wells in 2011 with capital of approximately
$30 million.
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Based on well results, the company plans to drill 6 or more wells
annually beginning in 2012.
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Based on 640-acre spacing, the acreage holds over 75 potential
drill sites. Estimated gross ultimate recovery rates per well are
250,000 to 400,000 Bbls.
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Bakken - Richland County, Montana
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The company recently acquired approximately 20,000 net exploratory
leasehold acres, targeting the Three Forks formation.
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Niobrara - southeastern Wyoming
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The company holds approximately 65,000 net exploratory leasehold
acres in this emerging oil play. It is completing seismic
evaluation work on this acreage and expects to begin drilling 4
exploratory wells in 2011.
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If successful, the company plans to initiate a drilling program of
approximately 8 wells annually starting in 2012.
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The company also expects to participate in various non-operated
wells in the Niobrara.
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The company has more than 100 future locations on this acreage
based on 640-acre spacing. Although this is an emerging
exploratory play, early results by certain other producers appear
promising.
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Paradox Basin - Cane Creek Federal Unit, Utah
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The company holds approximately 75,000 net exploratory leasehold
acres.
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An Environmental Assessment for 9 wells was recently received by
the company.
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The company is evaluating its drilling options.
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Texas
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The company is targeting areas that have the potential for higher
liquids content. It has approximately $50 million of capital
targeted in 2011.
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Other Opportunities
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The company holds approximately 80,000 net exploratory leasehold
acres in the Heath Shale oil prospect in Montana. Plans include
drilling 1 or 2 appraisal wells in 2011.
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The company continues to pursue acquisitions of additional
leaseholds. Approximately $50 million of capital has been
allocated to leasehold acquisitions in 2011, focusing on expansion
of existing positions and new opportunities.
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Earnings guidance reflects estimated natural gas and oil prices for
August through December as follows:
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Natural Gas Index:
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NYMEX
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$4.00 to $4.50 per Mcf
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Ventura
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$3.75 to $4.25 per Mcf
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CIG
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$3.75 to $4.25 per Mcf
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Crude Oil Index:
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NYMEX
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$90.00 to $95.00 per barrel
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For the last six months of 2011, the company has hedged approximately
55 percent to 60 percent of its estimated natural gas production and
60 percent to 65 percent of its estimated oil production. For 2012, it
has hedged 20 percent to 25 percent of its estimated natural gas
production and 45 percent to 50 percent of its estimated oil
production. The hedges that are in place as of Aug. 1 are summarized
in the following chart:
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Forward
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Notional
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Period
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Volume
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Price
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Commodity
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Type
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Index
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Outstanding
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(MMBtu/Bbl)
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(Per MMBtu/Bbl)
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Natural Gas
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Swap
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HSC
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7/11 - 12/11
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680,800
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$8.00
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Natural Gas
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Swap
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NYMEX
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7/11 - 12/11
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2,024,000
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$6.1027
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Natural Gas
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Swap
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NYMEX
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7/11 - 12/11
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1,840,000
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$5.4975
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Natural Gas
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Swap
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NYMEX
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7/11 - 12/11
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1,840,000
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$4.58
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Natural Gas
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Swap
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NYMEX
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7/11 - 12/11
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1,840,000
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$4.70
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Natural Gas
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Swap
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NYMEX
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7/11 - 12/11
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1,840,000
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$4.75
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Natural Gas
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Swap
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NYMEX
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7/11 - 10/11
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1,230,000
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$4.775
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Natural Gas
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Swap
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Ventura
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7/11 - 10/11
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1,230,000
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$4.365
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Natural Gas
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Swap
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NYMEX
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1/12 - 12/12
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3,477,000
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$6.27
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Natural Gas
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Swap
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NYMEX
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1/12 - 12/12
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1,830,000
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$5.005
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Natural Gas
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Swap
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NYMEX
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1/12 - 12/12
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915,000
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$5.005
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Natural Gas
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Swap
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NYMEX
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1/12 - 12/12
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915,000
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$5.0125
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Natural Gas
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Swap
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Ventura
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1/12 - 12/12
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3,660,000
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$4.87
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Crude Oil
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Collar
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NYMEX
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7/11 - 12/11
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276,000
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$80.00-$94.00
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Crude Oil
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Collar
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NYMEX
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7/11 - 12/11
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184,000
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$80.00-$89.00
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Crude Oil
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Collar
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NYMEX
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7/11 - 12/11
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92,000
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$77.00-$86.45
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Crude Oil
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Collar
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NYMEX
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7/11 - 12/11
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92,000
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$75.00-$88.00
|
|
Crude Oil
|
|
Swap
|
|
NYMEX
|
|
7/11 - 12/11
|
|
184,000
|
|
$81.35
|
|
Crude Oil
|
|
Swap
|
|
NYMEX
|
|
7/11 - 12/11
|
|
92,000
|
|
$85.85
|
|
Crude Oil
|
|
Put Option
|
|
NYMEX
|
|
7/11 - 12/11
|
|
184,000
|
|
$80.00*
|
|
Crude Oil
|
|
Call Option
|
|
NYMEX
|
|
7/11 - 12/11
|
|
184,000
|
|
$103.00*
|
|
Crude Oil
|
|
Collar
|
|
NYMEX
|
|
1/12 - 12/12
|
|
366,000
|
|
$80.00-$87.80
|
|
Crude Oil
|
|
Collar
|
|
NYMEX
|
|
1/12 - 12/12
|
|
366,000
|
|
$80.00-$94.50
|
|
Crude Oil
|
|
Collar
|
|
NYMEX
|
|
1/12 - 12/12
|
|
366,000
|
|
$80.00-$98.36
|
|
Crude Oil
|
|
Collar
|
|
NYMEX
|
|
1/12 - 12/12
|
|
183,000
|
|
$85.00-$102.75
|
|
Crude Oil
|
|
Collar
|
|
NYMEX
|
|
1/12 - 12/12
|
|
183,000
|
|
$85.00-$103.00
|
|
Crude Oil
|
|
Swap
|
|
NYMEX
|
|
1/12 - 12/12
|
|
183,000
|
|
$100.10
|
|
Crude Oil
|
|
Swap
|
|
NYMEX
|
|
1/12 - 12/12
|
|
183,000
|
|
$100.00
|
|
Crude Oil
|
|
Swap
|
|
NYMEX
|
|
1/12 - 12/12
|
|
366,000
|
|
$110.30
|
|
Crude Oil
|
|
Collar
|
|
NYMEX
|
|
1/13 - 12/13
|
|
182,500
|
|
$95.00-$117.00
|
|
Crude Oil
|
|
Collar
|
|
NYMEX
|
|
1/13 - 12/13
|
|
182,500
|
|
$95.00-$117.00
|
|
Natural Gas
|
|
Basis Swap
|
|
CIG
|
|
7/11 - 12/11
|
|
2,024,000
|
|
$0.395
|
|
Natural Gas
|
|
Basis Swap
|
|
Ventura
|
|
7/11 - 12/11
|
|
1,840,000
|
|
$0.15
|
|
Natural Gas
|
|
Basis Swap
|
|
Ventura
|
|
7/11 - 12/11
|
|
920,000
|
|
$0.15
|
|
Natural Gas
|
|
Basis Swap
|
|
Ventura
|
|
7/11 - 12/11
|
|
460,000
|
|
$0.16
|
|
Natural Gas
|
|
Basis Swap
|
|
Ventura
|
|
7/11 - 12/11
|
|
1,840,000
|
|
$0.16
|
|
Natural Gas
|
|
Basis Swap
|
|
Ventura
|
|
7/11 - 12/11
|
|
2,300,000
|
|
$0.155
|
|
Natural Gas
|
|
Basis Swap
|
|
CIG
|
|
1/12 - 12/12
|
|
2,745,000
|
|
$0.405
|
|
Natural Gas
|
|
Basis Swap
|
|
CIG
|
|
1/12 - 12/12
|
|
732,000
|
|
$0.41
|
|
* Deferred premium of $4.00. Put option was purchased. Call option
was sold.
Notes:
-
Ventura is an index pricing point related to Northern Natural
Gas Co.'s system; CIG is an index pricing point related to
Colorado Interstate Gas Co.'s system; HSC is the Houston Ship
Channel hub in southeast Texas which connects to several
pipelines.
-
For all basis swaps, Index prices are below NYMEX prices and are
reported as a positive amount in the Price column.
|
Regulated
Pipeline and Energy Services
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2011
|
|
2010
|
|
|
2011
|
|
2010
|
|
|
|
|
(Dollars in millions)
|
|
|
Operating revenues
|
|
|
$
|
72.4
|
|
|
$
|
80.5
|
|
|
|
$
|
146.4
|
|
|
$
|
169.1
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased natural gas sold
|
|
|
|
33.9
|
|
|
|
35.3
|
|
|
|
|
68.0
|
|
|
|
82.8
|
|
|
Operation and maintenance
|
|
|
|
18.6
|
|
|
|
17.8
|
|
|
|
|
36.2
|
|
|
|
33.0
|
|
|
Depreciation, depletion and amortization
|
|
|
|
6.4
|
|
|
|
6.5
|
|
|
|
|
12.8
|
|
|
|
12.9
|
|
|
Taxes, other than income
|
|
|
|
3.4
|
|
|
|
3.2
|
|
|
|
|
7.0
|
|
|
|
6.2
|
|
|
|
|
|
|
62.3
|
|
|
|
62.8
|
|
|
|
|
124.0
|
|
|
|
134.9
|
|
|
Operating income
|
|
|
|
10.1
|
|
|
|
17.7
|
|
|
|
|
22.4
|
|
|
|
34.2
|
|
|
Earnings
|
|
|
$
|
4.8
|
|
|
$
|
9.5
|
|
|
|
$
|
11.7
|
|
|
$
|
18.3
|
|
|
Transportation volumes (MMdk)
|
|
|
|
25.8
|
|
|
|
44.3
|
|
|
|
|
53.1
|
|
|
|
74.8
|
|
|
Gathering volumes (MMdk)
|
|
|
|
16.9
|
|
|
|
19.3
|
|
|
|
|
34.4
|
|
|
|
38.4
|
|
|
Customer natural gas storage balance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
|
32.9
|
|
|
|
43.5
|
|
|
|
|
58.8
|
|
|
|
61.5
|
|
|
Net injection (withdrawal)
|
|
|
|
(1.2
|
)
|
|
|
20.7
|
|
|
|
|
(27.1
|
)
|
|
|
2.7
|
|
|
End of period
|
|
|
|
31.7
|
|
|
|
64.2
|
|
|
|
|
31.7
|
|
|
|
64.2
|
|
This segment reported second quarter earnings of $4.8 million, compared
to $9.5 million for the same period in 2010. The earnings decrease
reflects lower volumes transported to storage, lower storage services
revenue, as well as lower gathering volumes.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
The company continues to pursue expansion of facilities and services
offered to customers. Energy development within its geographic region,
which includes portions of Colorado, Wyoming, Montana and North
Dakota, is expanding, most notably the Bakken of North Dakota and
eastern Montana. It owns an extensive natural gas pipeline system in
the Bakken area. Ongoing energy development is expected to have many
direct and indirect benefits to this business.
-
The company solicited customer interest in a 27 MMcf per day expansion
of its existing natural gas pipeline in the Bakken production area in
northwestern North Dakota in the first quarter of 2011. Sufficient
customer interest was received to move forward on a project.
Construction is underway and the capacity is projected to be in
service in late third quarter.
-
Final preparations are underway for the construction of approximately
12 miles of high pressure transmission pipeline providing takeaway
capacity from Bear Paw Energy's Garden Creek processing facility being
constructed in northwestern North Dakota. The pipeline project is
expected to be completed in the fourth quarter.
-
The company has recently executed agreements to build approximately 13
miles of high pressure transmission pipeline from the Stateline I and
II processing facilities in northwestern North Dakota to deliver gas
into the Northern Border Pipeline. It has a projected completion date
of mid 2012.
-
The company has three natural gas storage fields including the largest
storage field in North America located near Baker, Montana. It
continues to seek interest in its storage services and is pursuing a
project to increase its firm deliverability from the Baker Storage
field by 125 MMcf per day. The company has received commitment on
approximately 30 percent of the total potential project and is moving
forward on this phase with a projected in-service date of
November 2011.
Electric and Natural Gas Utilities
|
Electric
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
|
|
(Dollars in millions, where applicable)
|
|
Operating revenues
|
|
$
|
50.0
|
|
|
$
|
45.7
|
|
|
$
|
107.8
|
|
|
$
|
95.4
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
Fuel and purchased power
|
|
|
14.5
|
|
|
|
13.1
|
|
|
|
31.4
|
|
|
|
30.0
|
|
|
Operation and maintenance
|
|
|
18.3
|
|
|
|
16.2
|
|
|
|
34.3
|
|
|
|
31.4
|
|
|
Depreciation, depletion and amortization
|
|
|
7.9
|
|
|
|
6.1
|
|
|
|
16.1
|
|
|
|
11.9
|
|
|
Taxes, other than income
|
|
|
2.5
|
|
|
|
2.2
|
|
|
|
5.0
|
|
|
|
4.8
|
|
|
|
|
|
43.2
|
|
|
|
37.6
|
|
|
|
86.8
|
|
|
|
78.1
|
|
|
Operating income
|
|
|
6.8
|
|
|
|
8.1
|
|
|
|
21.0
|
|
|
|
17.3
|
|
|
Earnings
|
|
$
|
4.8
|
|
|
$
|
5.0
|
|
|
$
|
13.3
|
|
|
$
|
10.8
|
|
|
Retail sales (million kWh)
|
|
|
614.6
|
|
|
|
615.2
|
|
|
|
1,409.3
|
|
|
|
1,365.0
|
|
|
Sales for resale (million kWh)
|
|
|
21.8
|
|
|
|
7.6
|
|
|
|
28.5
|
|
|
|
37.4
|
|
|
Average cost of fuel and purchased
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
power per kWh
|
|
$
|
.021
|
|
|
$
|
.020
|
|
|
$
|
.021
|
|
|
$
|
.020
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Distribution
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
|
|
(Dollars in millions)
|
|
Operating revenues
|
|
$
|
164.6
|
|
|
$
|
160.1
|
|
|
$
|
535.0
|
|
|
$
|
509.2
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
Purchased natural gas sold
|
|
|
102.0
|
|
|
|
98.9
|
|
|
|
359.4
|
|
|
|
344.1
|
|
|
Operation and maintenance
|
|
|
33.3
|
|
|
|
34.4
|
|
|
|
67.6
|
|
|
|
67.1
|
|
|
Depreciation, depletion and amortization
|
|
|
11.2
|
|
|
|
10.7
|
|
|
|
22.4
|
|
|
|
21.4
|
|
|
Taxes, other than income
|
|
|
10.6
|
|
|
|
10.5
|
|
|
|
28.4
|
|
|
|
27.0
|
|
|
|
|
|
157.1
|
|
|
|
154.5
|
|
|
|
477.8
|
|
|
|
459.6
|
|
|
Operating income
|
|
|
7.5
|
|
|
|
5.6
|
|
|
|
57.2
|
|
|
|
49.6
|
|
|
Earnings
|
|
$
|
1.9
|
|
|
$
|
.1
|
|
|
$
|
29.4
|
|
|
$
|
23.4
|
|
|
Volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
17.3
|
|
|
|
15.6
|
|
|
|
61.3
|
|
|
|
53.7
|
|
|
Transportation
|
|
|
25.6
|
|
|
|
28.9
|
|
|
|
59.7
|
|
|
|
63.4
|
|
|
Total throughput
|
|
|
42.9
|
|
|
|
44.5
|
|
|
|
121.0
|
|
|
|
117.1
|
|
|
Degree days (% of normal)*
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
120
|
%
|
|
|
96
|
%
|
|
|
112
|
%
|
|
|
98
|
%
|
|
Cascade
|
|
|
118
|
%
|
|
|
118
|
%
|
|
|
107
|
%
|
|
|
95
|
%
|
|
Intermountain
|
|
|
141
|
%
|
|
|
132
|
%
|
|
|
113
|
%
|
|
|
103
|
%
|
|
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
|
The combined utility businesses reported earnings of $6.7 million in the
second quarter of 2011, compared to $5.1 million for the same period in
2010. The increase in earnings reflects increased retail natural gas
sales volumes resulting from colder weather than last year, higher
electric retail sales margins and lower income taxes. These increases
were partially offset by higher operation and maintenance expense,
increased depreciation, depletion and amortization expense, lower other
income and higher net interest expense.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
In April 2010, the company filed an application with the North Dakota
Public Service Commission for an electric rate increase of
$15.4 million annually, or approximately 14 percent above current
rates. The requested increase included the investment in
infrastructure upgrades, recovery of the investment in renewable
generation, the costs associated with the Big Stone II plant and the
significant loss of wholesale sales margins. In June 2010, the NDPSC
approved an interim increase of $7.6 million effective with service
rendered June 18, 2010. In June 2010, the company and the NDPSC
Advocacy Staff filed a partial settlement agreement agreeing to an
overall rate of return and a sharing of earnings over a specified
return on equity. In July 2010, the company filed an amendment to its
application to exclude the development costs associated with the Big
Stone II plant because of a settlement agreement approved by the NDPSC
that provided for recovery of such development costs. In November, the
company and the NDPSC Advocacy Staff filed a second settlement
agreement resolving certain issues. The company revised its requested
rate increase to $8.8 million annually or 7.7 percent as a result of
the settlements, the exclusion of the Big Stone II plant development
costs and other adjustments. The NDPSC Advocacy Staff sought
reductions of $8.3 million annually from the company's requested
increase. A hearing on the application was held in November. On
March 14, the company, the NDPSC Advocacy Staff and the Missouri
Valley Resource Council filed a settlement agreement that resolved all
outstanding issues in the case, resulting in an increase of
$7.6 million annually. On June 8, the NDPSC approved the settlements.
Final rates were implemented effective with service rendered July 22.
-
In August 2010, the company filed an application with the Montana
Public Service Commission for an electric rate increase of
$5.5 million annually, or approximately 13 percent above current
rates. The requested increase included the investment in
infrastructure upgrades, recovery of the investment in renewable
generation, the costs associated with the Big Stone II plant and the
significant loss of wholesale sales margins. Montana-Dakota requested
an interim increase of $3.1 million or approximately 7.4 percent. On
Feb. 8, the MTPSC approved an interim increase of $2.6 million or
approximately 6.3 percent, effective with service rendered Feb. 14. In
May, Montana-Dakota and interveners to the case filed a settlement
agreement with the MTPSC at the interim increase level. The MTPSC held
a hearing on the settlement on June 29 and approved the settlement
agreement on July 26.
-
On July 7, the company filed for an advance determination of prudence
with the NDPSC on the construction of an 88-MW simple cycle natural
gas turbine and associated facilities projected to be in service in
2015. The turbine will be located on currently owned property that is
adjacent to the company's Heskett Generating Station near Mandan,
North Dakota and is required to meet the capacity requirements of the
company's integrated electric system service customers. The capacity
will be a partial replacement for third party contract capacity
expiring in 2015. Project cost is estimated to be $85.6 million. An
order is expected in the first quarter of 2012.
-
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 currently served by fuel oil or propane, and to serve new
customers.
-
The company is currently involved with a number of pipeline looping
projects to enhance the reliability and deliverability of its system
in the Pacific Northwest.
-
The company is pursuing opportunities associated with the potential
development of high-voltage transmission lines and system enhancements
targeted towards delivery of renewable energy from the wind rich
regions that lie within its traditional electric service territory to
major market areas. The company has signed a contract to develop a
30-mile high-voltage power line in southeast North Dakota to move
power to the electric grid from a proposed 150-MW wind farm. The
proposed project will total approximately $20 million and will include
substation upgrades with construction expected to begin in the third
quarter 2011. Its customers would not bear any of the costs associated
with the project as costs will be recovered through an approved
interconnect tariff. The NDPSC has approved the route permits for this
project. The project is expected to be completed in the first quarter
of 2012. A major market party to the wind farm project has announced
its intentions to withdraw from the project which may affect
development and timing of the associated power line by the company.
-
The South Dakota Board of Minerals and Environment has approved rules
implementing the South Dakota Regional Haze Program that upon approval
by the EPA will require the Big Stone Station to install and operate a
best available retrofit technology (BART) air quality control system
to reduce emissions of particulate matter, sulfur dioxide and nitrogen
oxides as early as practicable, but not later than five years after
EPA's approval of the state program. The state program was submitted
Jan. 21. The company's share of the cost of this air quality control
system could exceed $100 million. At this time the company believes
continuing to operate Big Stone Station with the upgrade is the best
option; however, it will continue to review alternatives. The company
intends to seek recovery of costs related to the above matter in
electric rates charged to customers. On May 20, the company filed for
an advance determination of prudence with the NDPSC requesting advance
determination that the air quality control system is reasonable and
prudent. An order is expected in early 2012.
Construction
|
Construction Materials and Contracting
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
(Dollars in millions)
|
|
Operating revenues
|
|
|
$
|
375.6
|
|
|
|
$
|
361.6
|
|
|
|
$
|
519.2
|
|
|
|
$
|
511.4
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
|
334.2
|
|
|
|
|
316.9
|
|
|
|
|
481.1
|
|
|
|
|
462.9
|
|
|
Depreciation, depletion and amortization
|
|
|
|
21.2
|
|
|
|
|
22.2
|
|
|
|
|
42.6
|
|
|
|
|
44.8
|
|
|
Taxes, other than income
|
|
|
|
9.8
|
|
|
|
|
9.2
|
|
|
|
|
17.5
|
|
|
|
|
16.5
|
|
|
|
|
|
|
365.2
|
|
|
|
|
348.3
|
|
|
|
|
541.2
|
|
|
|
|
524.2
|
|
|
Operating income (loss)
|
|
|
|
10.4
|
|
|
|
|
13.3
|
|
|
|
|
(22.0
|
)
|
|
|
|
(12.8
|
)
|
|
Earnings (loss)
|
|
|
$
|
5.0
|
|
|
|
$
|
5.7
|
|
|
|
$
|
(16.4
|
)
|
|
|
$
|
(14.5
|
)
|
|
Sales (000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates (tons)
|
|
|
|
6,479
|
|
|
|
|
6,261
|
|
|
|
|
9,306
|
|
|
|
|
9,224
|
|
|
Asphalt (tons)
|
|
|
|
1,842
|
|
|
|
|
1,579
|
|
|
|
|
2,007
|
|
|
|
|
1,733
|
|
|
Ready-mixed concrete (cubic yards)
|
|
|
|
698
|
|
|
|
|
742
|
|
|
|
|
1,095
|
|
|
|
|
1,218
|
|
The construction materials and contracting segment reported second
quarter earnings of $5.0 million, compared to $5.7 million for the same
period in 2010. The decrease in earnings largely resulted from lower
ready-mixed concrete margins and volumes, lower margins from other
product lines and lower gains from property sales. These decreases were
partially offset by increased construction margins, higher asphalt
volumes and margins, lower selling, general and administrative costs and
lower interest expense.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
Work backlog as of June 30 was approximately $649 million, with
93 percent of construction backlog being public work and private
representing 7 percent. In the company's peak earnings year of 2006,
private backlog represented 40 percent of construction backlog.
Backlog a year ago was $677 million. Total backlog at March 31 was
$569 million.
-
Examples of projects in work backlog include several highway paving
projects, airports, bridge work, reclamation and harbor expansion
projects.
-
The company is part of a joint venture that was selected as the low
bidder on the Port of Long Beach expansion. Its share of the project
for this phase is expected to exceed $25 million. The company has
green fielded an operation in Williston, North Dakota and was recently
awarded a $33 million highway project in the Bakken area of North
Dakota. It also expects to place a new asphalt oil terminal into
service in late 2011 in Wyoming.
-
As a result of the continued slow recovery in the residential and
commercial markets and uncertainty in federal and state transportation
funding, the company expects overall 2011 volumes to be comparable to
2010.
-
Federal transportation stimulus of $7.9 billion was directed to states
where the company operates. Of that amount, 74 percent was spent as of
June 30, with the majority of the remaining $2.0 billion to be spent
during the remainder of 2011.
-
The company is the primary cement provider and has the opportunity to
supply a portion of the ready-mixed concrete and aggregate related to
a multi-phased light rail project in Hawaii.
-
The company continues to pursue work related to energy projects, such
as wind towers, transmission projects, geothermal and refineries. It
is also pursuing opportunities for expansion of its existing business
lines including initiatives aimed at capturing additional market share
and expansion into new markets.
-
The company has a strong emphasis on operational efficiencies and cost
reduction. SG&A expenses are down more than 40 percent for the
trailing twelve months through June 30, compared to the annual
expenses in 2006, the peak earnings year for this segment.
-
As the country's 5th 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.
|
Construction Services
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
(In millions)
|
|
Operating revenues
|
|
|
$
|
198.1
|
|
|
$
|
188.2
|
|
|
$
|
401.5
|
|
|
$
|
341.3
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
|
178.3
|
|
|
|
173.2
|
|
|
|
363.2
|
|
|
|
315.0
|
|
Depreciation, depletion and amortization
|
|
|
|
2.8
|
|
|
|
3.1
|
|
|
|
5.8
|
|
|
|
6.3
|
|
Taxes, other than income
|
|
|
|
5.5
|
|
|
|
6.1
|
|
|
|
13.2
|
|
|
|
12.6
|
|
|
|
|
|
186.6
|
|
|
|
182.4
|
|
|
|
382.2
|
|
|
|
333.9
|
|
Operating income
|
|
|
|
11.5
|
|
|
|
5.8
|
|
|
|
19.3
|
|
|
|
7.4
|
|
Earnings
|
|
|
$
|
6.1
|
|
|
$
|
2.9
|
|
|
$
|
10.8
|
|
|
$
|
3.1
|
This segment had second quarter earnings of $6.1 million, compared to
$2.9 million a year ago. This increase reflects higher construction
workloads and margins in the Western region, partially offset by lower
construction workloads and margins in the Mountain region. Also
contributing to the earnings increase were higher equipment and
electrical supply sales.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
Work backlog as of June 30 was approximately $364 million, compared to
$389 million a year ago, and $347 million at March 31. The backlog
includes a variety of projects such as substation and line
construction, solar and other commercial, institutional and industrial
projects including refinery work.
-
As a result of the continued slow economic recovery, the company
anticipates margins in 2011 to be comparable to 2010 levels.
-
The company is pursuing expansion in high-voltage transmission and
substation construction, renewable resource construction, governmental
facilities, refinery turnaround projects and utility service work.
-
The company continues to focus on costs and efficiencies to enhance
margins. SG&A expenses are down more than 30 percent for the trailing
twelve months through June 30, compared to the annual expenses in
2008, the peak earnings year for this segment.
-
With its highly skilled technical workforce, this group is prepared to
take advantage of government stimulus spending on transmission
infrastructure.
Other
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
|
|
(In millions)
|
|
Operating revenues
|
|
|
$
|
2.8
|
|
|
|
$
|
2.3
|
|
|
|
$
|
5.3
|
|
|
|
$
|
4.5
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
|
1.9
|
|
|
|
|
1.8
|
|
|
|
|
4.9
|
|
|
|
|
3.7
|
|
|
Depreciation, depletion and amortization
|
|
|
|
.4
|
|
|
|
|
.4
|
|
|
|
|
.7
|
|
|
|
|
.8
|
|
|
Taxes, other than income
|
|
|
|
---
|
|
|
|
|
.1
|
|
|
|
|
.1
|
|
|
|
|
.1
|
|
|
|
|
|
|
2.3
|
|
|
|
|
2.3
|
|
|
|
|
5.7
|
|
|
|
|
4.6
|
|
|
Operating income (loss)
|
|
|
|
.5
|
|
|
|
|
---
|
|
|
|
|
(.4
|
)
|
|
|
|
(.1
|
)
|
|
Income from continuing operations
|
|
|
|
1.1
|
|
|
|
|
1.6
|
|
|
|
|
1.1
|
|
|
|
|
3.0
|
|
|
Income (loss) from discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations, net of tax
|
|
|
|
(.1
|
)
|
|
|
|
---
|
|
|
|
|
.2
|
|
|
|
|
---
|
|
|
Earnings
|
|
|
$
|
1.0
|
|
|
|
$
|
1.6
|
|
|
|
$
|
1.3
|
|
|
|
$
|
3.0
|
|
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 chief executive officer 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 natural gas and oil production and pipeline and energy
services businesses are dependent on factors, including commodity
prices and commodity price basis differentials, which are subject to
various external influences that cannot be controlled.
-
The regulatory approval, permitting, construction, startup and
operation of power generation facilities may involve unanticipated
changes 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 services and construction
materials and contracting businesses are subject to delay or
cancellation and may not be realized.
-
Actual quantities of recoverable natural gas and oil reserves and
discounted future net cash flows from those reserves may vary
significantly from estimated amounts.
-
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.
-
Global climate change initiatives to reduce greenhouse gas emissions
could adversely impact the company's electric generation operations.
-
The company's coalbed natural gas operations could be adversely
impacted by the outcome of lawsuits challenging its coalbed natural
gas development.
-
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 and
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.
-
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
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
2011
|
|
2010
|
|
2011
|
|
2010
|
|
|
|
(In millions, except per share amounts)
|
|
|
|
(Unaudited)
|
|
Operating revenues
|
|
$
|
930.8
|
|
|
$
|
906.4
|
|
|
$
|
1,832.6
|
|
|
$
|
1,741.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel and purchased power
|
|
|
14.5
|
|
|
|
13.1
|
|
|
|
31.4
|
|
|
|
30.0
|
|
|
Purchased natural gas sold
|
|
|
101.6
|
|
|
|
97.4
|
|
|
|
346.2
|
|
|
|
331.1
|
|
|
Operation and maintenance
|
|
|
606.6
|
|
|
|
585.3
|
|
|
|
1,034.4
|
|
|
|
962.1
|
|
|
Depreciation, depletion and amortization
|
|
|
83.3
|
|
|
|
81.5
|
|
|
|
168.0
|
|
|
|
160.2
|
|
|
Taxes, other than income
|
|
|
42.5
|
|
|
|
40.4
|
|
|
|
92.2
|
|
|
|
86.2
|
|
|
|
|
|
848.5
|
|
|
|
817.7
|
|
|
|
1,672.2
|
|
|
|
1,569.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
82.3
|
|
|
|
88.7
|
|
|
|
160.4
|
|
|
|
171.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from equity method investments
|
|
|
.9
|
|
|
|
2.2
|
|
|
|
1.4
|
|
|
|
4.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income
|
|
|
1.9
|
|
|
|
2.7
|
|
|
|
3.8
|
|
|
|
5.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
20.0
|
|
|
|
20.5
|
|
|
|
42.0
|
|
|
|
41.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
65.1
|
|
|
|
73.1
|
|
|
|
123.6
|
|
|
|
140.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes
|
|
|
19.9
|
|
|
|
24.2
|
|
|
|
35.8
|
|
|
|
49.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
45.2
|
|
|
|
48.9
|
|
|
|
87.8
|
|
|
|
90.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net of tax
|
|
|
(.1
|
)
|
|
|
---
|
|
|
|
.2
|
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
45.1
|
|
|
|
48.9
|
|
|
|
88.0
|
|
|
|
90.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on preferred stocks
|
|
|
.2
|
|
|
|
.1
|
|
|
|
.3
|
|
|
|
.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings on common stock
|
|
$
|
44.9
|
|
|
$
|
48.8
|
|
|
$
|
87.7
|
|
|
$
|
90.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share - basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before discontinued operations
|
|
$
|
.24
|
|
|
$
|
.26
|
|
|
$
|
.46
|
|
|
$
|
.48
|
|
|
Discontinued operations, net of tax
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
Earnings per common share - basic
|
|
$
|
.24
|
|
|
$
|
.26
|
|
|
$
|
.46
|
|
|
$
|
.48
|
|
|
Earnings per common share - diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before discontinued operations
|
|
$
|
.24
|
|
|
$
|
.26
|
|
|
$
|
.46
|
|
|
$
|
.48
|
|
|
Discontinued operations, net of tax
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
Earnings per common share - diluted
|
|
$
|
.24
|
|
|
$
|
.26
|
|
|
$
|
.46
|
|
|
$
|
.48
|
|
|
Dividends per common share
|
|
$
|
.1625
|
|
|
$
|
.1575
|
|
|
$
|
.3250
|
|
|
$
|
.3150
|
|
|
Weighted average common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
outstanding - basic
|
|
|
188.8
|
|
|
|
188.1
|
|
|
|
188.7
|
|
|
|
188.0
|
|
|
Weighted average common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
outstanding - diluted
|
|
|
189.0
|
|
|
|
188.3
|
|
|
|
188.9
|
|
|
|
188.2
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
June 30,
|
|
|
|
|
2011
|
|
|
2010
|
|
|
|
|
(Unaudited)
|
|
Other Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
Book value per common share
|
|
|
$
|
14.36
|
|
|
|
$
|
13.89
|
|
|
Market price per common share
|
|
|
$
|
22.50
|
|
|
|
$
|
18.03
|
|
|
Dividend yield (indicated annual rate)
|
|
|
|
2.9
|
%
|
|
|
|
3.5
|
%
|
|
Price/earnings ratio*
|
|
|
|
17.9
|
x
|
|
|
|
13.3
|
x
|
|
Market value as a percent of book value
|
|
|
|
156.7
|
%
|
|
|
|
129.8
|
%
|
|
Return on average common equity*
|
|
|
|
8.9
|
%
|
|
|
|
10.0
|
%
|
|
Total assets**
|
|
|
$
|
6.3
|
|
|
|
$
|
6.1
|
|
|
Total equity**
|
|
|
$
|
2.7
|
|
|
|
$
|
2.6
|
|
|
Total debt**
|
|
|
$
|
1.4
|
|
|
|
$
|
1.6
|
|
|
Capitalization ratios:
|
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
|
66
|
%
|
|
|
|
62
|
%
|
|
Total debt
|
|
|
|
34
|
|
|
|
|
38
|
|
|
|
|
|
|
100
|
%
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Represents 12 months ended
|
|
** In billions
|
MDU Resources Group, Inc.
Financial:
Phyllis A.
Rittenbach
Director - Investor Relations
701-530-1057
or
Media:
Rick
Matteson
Director of Communications and Public Affairs
701-530-1700
Copyright © 2012, Business Wire, Inc., All rights reserved. Copyright © 2012, NewsBlaze, Daily News
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