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Published: February 02, 2011
MDU Resources Reports 2010 Results, Initiates Guidance for 2011
BISMARCK, N.D. - (BUSINESS WIRE) - MDU Resources Group, Inc. (NYSE:MDU) today reported 2010
consolidated earnings of $240.0 million, or $1.27 per share. This
compares to a 2009 loss of $124.0 million or 67 cents per share.
Excluding a third quarter arbitration charge at the pipeline segment and
a fourth quarter gain on the sale of the company's Brazilian
transmission lines, 2010 earnings were $242.7 million, or $1.29 per
share. Excluding a first quarter 2009 noncash charge at the natural gas
and oil production segment, 2009 earnings were $260.4 million, or
$1.40 per share.
In the fourth quarter 2010 the company had consolidated earnings of
$88.8 million, or 47 cents per share compared to $72.5 million or
38 cents per share in the fourth quarter of 2009. Excluding the gain on
the sale of the company's Brazilian transmission lines, earnings for the
fourth quarter 2010 were $75.0 million, or 40 cents per share.
"I am pleased with the performance of our businesses this year despite
lower realized natural gas prices and a challenging economic
environment," said Terry D. Hildestad, president and chief executive
officer of MDU Resources. "These results and our solid financial
condition once again demonstrate the value of our diversified business
strategy. We have a strong balance sheet and generated significant cash
from operations, as well as from the successful sale of our Brazilian
transmission assets, and the recently announced Niobrara transaction
where we de-risked our investment while maintaining significant
operating interest in the acreage."
Hildestad pointed out that MDU Resources' investments in the North
Dakota Bakken, which is one of the most active oil development areas in
the U.S., have been successful. This helped earnings at the company's
exploration and production business remain strong despite a 16 percent
decline in average realized natural gas prices. Oil production increased
5 percent in 2010 reflecting the group's effort to further balance its
production mix to benefit from favorable oil prices. A growing portion
of the business' 2011 capital budget will be focused on increasing oil
production.
"Our plans include adding an additional drilling rig in the second
quarter to accelerate our Bakken drilling activities," Hildestad said.
"We will also begin drilling test wells on our approximate 65,000 net
acres in the emerging Niobrara play."
The pipeline and energy services business also is well positioned to
benefit from the Bakken activity with an extensive natural gas
transmission pipeline system in the Bakken, and plans to expand its
capacity during 2011. The group reported record natural gas storage
levels during the third quarter at its storage fields, and is moving
forward this year with the first phase of a storage expansion to add
firm deliverability from its Baker storage field.
The utility business increased year-over-year earnings. This group
operates in growing service territories with a customer base that now
approximates 964,000 customers. The utility also added 55 megawatts of
rate-based generation in 2010, including 30 MW of renewable wind energy,
to maintain a reliable supply of electricity for customers. Looking
forward, this business is pursuing opportunities to invest in the
expected regional transmission build out and additional generation.
"The economy continues to affect volumes and margins for our
construction businesses," Hildestad added. "These are good solid
fundamental businesses for the long term that are weathering a very
challenging economic cycle. The leaner cost structure of these
businesses positions us well as bidding opportunities increase and the
potential for large multi-year projects are presented.
"For 2011, we are providing initial earnings guidance in the range of
$1.05 to $1.30 per common share. Our guidance factors in the
uncertainties presented by continued low private construction spending
and funding for public works projects, as well as continued low natural
gas prices. We are excited about the potential of our exploratory
drilling program and the organic growth opportunities at our regulated
operations. In addition, we continue to pursue acquisition opportunities
in each line of business."
The company will host a webcast at 11 a.m. EST Feb. 3 to discuss
earnings results and initial guidance for 2011. 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 (706) 645-9291 for international
callers, conference ID 34480118.
MDU Resources Group, Inc., a Fortune 500 company and 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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2010 Earnings
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2009 Earnings
|
|
Business Line
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|
(In Millions)
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|
(In Millions)
|
|
Exploration and Production
|
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|
|
|
|
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|
Natural gas and oil production
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$
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85.6
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$
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87.7
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Regulated
|
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Pipeline and energy services
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23.2
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*
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|
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37.8
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Electric and natural gas utilities
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65.9
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54.9
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Construction
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|
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Construction materials and contracting
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29.6
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47.1
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Construction services
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18.0
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25.6
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Other
|
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21.0
|
**
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7.3
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|
Earnings before discontinued operations and noncash charge
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243.3
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260.4
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Loss from discontinued operations, net of tax
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(3.3
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)
|
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|
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---
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Effects of noncash charge
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---
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(384.4
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)
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Earnings (loss) on common stock
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$
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240.0
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$
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(124.0
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)
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* Reflects a natural gas gathering arbitration charge of $16.5 million
after tax.
** Reflects a gain on the sale of the Brazilian
transmission lines of $13.8 million after tax.
On a consolidated basis, the following information highlights the key
growth strategies, projections and certain assumptions for the company:
-
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:
-
First quarter - 15 percent
-
Second quarter - 20 percent
-
Third quarter - 35 percent
-
Fourth quarter - 30 percent
-
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.
-
The company continually seeks opportunities to expand through
strategic acquisitions and organic growth opportunities.
-
Capital expenditures for 2010 and estimated capital expenditures for
2011 are noted in the following table. The company expects the 2011
estimated capital expenditures to be funded in its entirety with cash
flow generated from operations.
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Capital Expenditures
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Capital Expenditures
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2011 Estimated*
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2010 Actual
|
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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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|
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Natural gas and oil production
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|
$ 306
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|
|
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$ 356
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**
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Regulated
|
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Pipeline and energy services
|
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41
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|
|
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14
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Electric
|
|
76
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|
|
|
86
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Natural gas distribution
|
|
80
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|
|
75
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|
|
Construction
|
|
|
|
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Construction materials and contracting
|
|
39
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|
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26
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Construction services
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10
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15
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Other
|
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17
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|
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2
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Net proceeds and other
|
|
(8
|
)
|
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|
(79
|
)
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Total Capital Expenditures
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|
$ 561
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|
|
$ 495
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* Capital expenditures relative to potential acquisitions of businesses
would be incremental to these estimates.
** Includes approximately
$100 million for the acquisition of the Green River Basin properties.
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|
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|
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|
|
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|
|
Exploration and Production
|
|
|
|
|
|
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|
|
|
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Natural Gas and Oil Production
|
|
|
|
|
|
|
|
|
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|
Three Months Ended
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Twelve Months Ended
|
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|
December 31,
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December 31,
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|
|
2010
|
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2009
|
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2010
|
|
2009
|
|
|
|
(Dollars in millions, where applicable)
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Operating revenues:
|
|
|
|
|
|
|
|
|
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Natural gas
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|
$
|
51.9
|
|
$
|
74.0
|
|
|
$
|
219.6
|
|
$
|
292.3
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|
|
Oil
|
|
|
57.0
|
|
|
45.3
|
|
|
|
214.8
|
|
|
147.4
|
|
|
|
|
|
108.9
|
|
|
119.3
|
|
|
|
434.4
|
|
|
439.7
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance:
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs
|
|
|
16.9
|
|
|
15.9
|
|
|
|
68.5
|
|
|
70.1
|
|
|
Gathering and transportation
|
|
|
5.9
|
|
|
5.7
|
|
|
|
23.5
|
|
|
24.0
|
|
|
Other
|
|
|
7.6
|
|
|
10.2
|
|
|
|
32.5
|
|
|
39.2
|
|
|
Depreciation, depletion and amortization
|
|
|
34.1
|
|
|
27.9
|
|
|
|
130.5
|
|
|
129.9
|
|
|
Taxes, other than income:
|
|
|
|
|
|
|
|
|
|
|
Production and property taxes
|
|
|
8.9
|
|
|
7.9
|
|
|
|
35.5
|
|
|
29.1
|
|
|
Other
|
|
|
.1
|
|
|
.2
|
|
|
|
.7
|
|
|
.8
|
|
|
Write-down of natural gas and oil properties
|
|
|
---
|
|
|
---
|
|
|
|
---
|
|
|
620.0
|
|
|
|
|
|
73.5
|
|
|
67.8
|
|
|
|
291.2
|
|
|
913.1
|
|
|
Operating income (loss)
|
|
|
35.4
|
|
|
51.5
|
|
|
|
143.2
|
|
|
(473.4
|
)
|
|
Earnings (loss)
|
|
$
|
20.7
|
|
$
|
31.4
|
|
|
$
|
85.6
|
|
$
|
(296.7
|
)
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
12,653
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|
|
13,277
|
|
|
|
50,391
|
|
|
56,632
|
|
|
Oil (MBbls)
|
|
|
835
|
|
|
791
|
|
|
|
3,262
|
|
|
3,111
|
|
|
Total Production (MMcfe)
|
|
|
17,665
|
|
|
18,022
|
|
|
|
69,963
|
|
|
75,299
|
|
|
Average realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
4.10
|
|
$
|
5.57
|
|
|
$
|
4.36
|
|
$
|
5.16
|
|
|
Oil (per barrel)
|
|
$
|
68.30
|
|
$
|
57.30
|
|
|
$
|
65.85
|
|
$
|
47.38
|
|
|
Average realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
3.07
|
|
$
|
3.55
|
|
|
$
|
3.57
|
|
$
|
2.99
|
|
|
Oil (per barrel)
|
|
$
|
71.09
|
|
$
|
62.52
|
|
|
$
|
66.71
|
|
$
|
49.76
|
|
|
Average depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
amortization rate, per equivalent Mcf
|
|
$
|
1.84
|
|
$
|
1.47
|
|
|
$
|
1.77
|
|
$
|
1.64
|
|
|
Production costs, including taxes, per
|
|
|
|
|
|
|
|
|
|
|
equivalent Mcf:
|
|
|
|
|
|
|
|
|
|
|
Lease operating costs
|
|
$
|
.96
|
|
$
|
.88
|
|
|
$
|
.98
|
|
$
|
.93
|
|
|
Gathering and transportation
|
|
|
.33
|
|
|
.31
|
|
|
|
.34
|
|
|
.32
|
|
|
Production and property taxes
|
|
|
.50
|
|
|
.44
|
|
|
|
.51
|
|
|
.39
|
|
|
|
|
$
|
1.79
|
|
$
|
1.63
|
|
|
$
|
1.83
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
Natural Gas
|
|
Oil
|
|
|
Natural Gas
|
|
Oil
|
|
|
|
(MMcf/MBbls)
|
|
Production by region:
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountain
|
|
|
39,160
|
|
|
2,365
|
|
|
|
41,635
|
|
|
2,182
|
|
|
Mid-Continent/Gulf States*
|
|
|
11,231
|
|
|
897
|
|
|
|
14,997
|
|
|
929
|
|
|
Total Production
|
|
|
50,391
|
|
|
3,262
|
|
|
|
56,632
|
|
|
3,111
|
|
|
* Includes Offshore Gulf of Mexico.
|
|
|
|
|
|
|
|
|
|
|
|
Earnings at this segment were $85.6 million for 2010, compared to
$87.7 million for 2009, which excludes the effect of a $384.4 million
after-tax noncash charge. This decrease reflects 16 percent lower
average realized natural gas prices, decreased natural gas production of
11 percent, as well as higher production taxes. These decreases were
partially offset by 39 percent higher average realized oil prices,
increased oil production of 5 percent and lower general and
administrative costs.
Fourth quarter earnings were $20.7 million, compared to 2009 fourth
quarter earnings of $31.4 million. This decrease reflects 26 percent
lower average realized natural gas prices and increased depreciation,
depletion and amortization expense, partially offset by 19 percent
higher average realized oil prices.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
The company expects to spend approximately $306 million in capital
expenditures in 2011. 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. The
company's 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.
-
For 2011, the company expects a 5 percent to 10 percent increase in
oil production offset by a 4 percent to 8 percent decrease in natural
gas production. If natural gas prices recover, the company believes it
is positioned to spend additional capital on drilling its low cost
natural gas properties.
-
Bakken - Mountrail County, North Dakota –
-
The company owns approximately 16,000 net acres of leaseholds
targeting the middle Bakken and Three Forks formations with
average production of approximately 3,700 net barrels per day. The
drilling of 13 operated and participation in various non-operated
wells is planned for 2011 with approximately $52 million of
capital expenditures. The company plans to drill 12 wells annually
for the two-year period 2012 through 2013.
-
Over 50 future wells sites have been identified, 20 middle Bakken
infill locations and the remainder Three Forks locations.
Estimated gross ultimate recovery per well for the middle Bakken
wells is 250,000 barrels to 400,000 barrels.
-
Bakken - Stark County, North Dakota –
-
The company holds approximately 50,000 net exploratory leasehold
acres, targeting the Three Forks formation. The first test well
was recently completed, the Kostelecky 31-6H, with an initial
24-hour production rate of 1,257 barrels of oil and 519 Mcf of
gas, or 1,343 barrels of oil equivalents. Its second test well,
the Oukrop 34-34H, was also recently completed. While it has not
been production tested, initial flow back of fluids is less than
expected. A third test well, Wock 14-11H, is drilled and waiting
on completion. The company anticipates drilling 6 additional
operated wells on this acreage and participating in various
non-operated wells in Stark County in 2011 with capital of
approximately $37 million.
-
Based on well results, the company plans to drill 12 or more wells
annually beginning in 2012.
-
Based on 640-acre spacing, the acreage holds over 75 potential
drill sites. Estimated gross ultimate recovery rates per well are
250,000 to 500,000 barrels of oil equivalents. Based on initial
well results and results by other producers, the play appears
promising.
-
Bakken –
-
In the second quarter, the company plans to add an additional
drilling rig in the Bakken.
-
Niobrara - southeastern Wyoming –
-
The company holds approximately 65,000 net exploratory leasehold
acres in this emerging oil play. The company is completing seismic
evaluation work on this acreage and expects to begin drilling 2
exploratory wells in 2011.
-
If successful, the company plans to initiate a drilling program of
approximately 12 wells annually starting in 2012.
-
The company also expects to participate in various non-operated
wells in the Niobrara.
-
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.
-
Texas –
-
Based on low natural gas prices, the company is targeting areas
that have the potential for higher liquids content. The company
has approximately $48 million of capital targeted in 2011.
-
Other Opportunities –
-
The company holds approximately 80,000 net exploratory leasehold
acres in the Heath Shale oil prospect in Montana. Plans include
drilling a test well in 2011.
-
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.
-
Reserve information –
-
The company's combined proved natural gas and oil reserves as of
Dec. 31 were 646 Bcfe, compared to 654 Bcfe at Dec. 31, 2009. The
change reflects approximately 57 Bcfe of extensions and
discoveries, 61 Bcfe of purchases, 70 Bcfe of production and
56 Bcfe of negative reserve revisions, which include 16 Bcfe of
proved undeveloped reserves that were removed as the reserves will
not be developed within the required five-year period. The Dec. 31
proved reserve figure does not yet include reserves for the
company's acreage in the Bakken - Stark County or Niobrara areas
because of the exploratory nature of these plays.
-
Earnings guidance reflects estimated natural gas and oil prices for
February through December as follows:
|
|
|
|
|
Natural Gas Index
|
|
|
|
NYMEX
|
|
$4.25 to $4.75 per Mcf
|
|
Ventura
|
|
$4.00 to $4.50 per Mcf
|
|
CIG
|
|
$3.75 to $4.25 per Mcf
|
|
|
|
|
|
Crude Oil Index
|
|
|
|
NYMEX
|
|
$85.00 to $90.00 per barrel
|
|
|
|
|
-
For 2011, the company has hedged approximately 45 percent to
50 percent of its estimated natural gas production and 60 percent to
65 percent of its estimated oil production. For 2012, the company has
hedged 15 percent to 20 percent of its estimated natural gas
production and 35 percent to 40 percent of its estimated oil
production. The hedges that are in place as of Feb. 2 are summarized
in the following chart:
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|
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|
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|
|
Forward
|
|
|
|
|
|
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|
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|
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|
Notional
|
|
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Period
|
|
|
Volume
|
|
|
Price
|
|
Commodity
|
|
|
Type
|
|
|
Index
|
|
|
Outstanding
|
|
|
(MMBtu/Bbl)
|
|
|
(Per MMBtu/Bbl)
|
|
Natural Gas
|
|
|
Collar
|
|
|
NYMEX
|
|
|
1/11 - 3/11
|
|
|
450,000
|
|
|
$5.62-$6.50
|
|
Natural Gas
|
|
|
Swap
|
|
|
HSC
|
|
|
1/11 - 12/11
|
|
|
1,350,500
|
|
|
$8.00
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
4,015,000
|
|
|
$6.1027
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
3,650,000
|
|
|
$5.4975
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
3,650,000
|
|
|
$4.58
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
2/11 - 12/11
|
|
|
3,340,000
|
|
|
$4.70
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
2/11 - 12/11
|
|
|
3,340,000
|
|
|
$4.75
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
4/11 - 10/11
|
|
|
2,140,000
|
|
|
$4.775
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/12 - 12/12
|
|
|
3,477,000
|
|
|
$6.27
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/12 - 12/12
|
|
|
1,830,000
|
|
|
$5.005
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/12 - 12/12
|
|
|
915,000
|
|
|
$5.005
|
|
Natural Gas
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/12 - 12/12
|
|
|
915,000
|
|
|
$5.0125
|
|
Crude Oil
|
|
|
Collar
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
547,500
|
|
|
$80.00-$94.00
|
|
Crude Oil
|
|
|
Collar
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
365,000
|
|
|
$80.00-$89.00
|
|
Crude Oil
|
|
|
Collar
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
182,500
|
|
|
$77.00-$86.45
|
|
Crude Oil
|
|
|
Collar
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
182,500
|
|
|
$75.00-$88.00
|
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
365,000
|
|
|
$81.35
|
|
Crude Oil
|
|
|
Swap
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
182,500
|
|
|
$85.85
|
|
Crude Oil
|
|
|
Put Option
|
|
|
NYMEX
|
|
|
1/11 - 12/11
|
|
|
365,000
|
|
|
$80.00*
|
|
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
|
|
Natural Gas
|
|
|
Basis Swap
|
|
|
Ventura
|
|
|
1/11 - 3/11
|
|
|
450,000
|
|
|
$0.135
|
|
Natural Gas
|
|
|
Basis Swap
|
|
|
CIG
|
|
|
1/11 - 12/11
|
|
|
4,015,000
|
|
|
$0.395
|
|
Natural Gas
|
|
|
Basis Swap
|
|
|
Ventura
|
|
|
1/11 - 12/11
|
|
|
3,650,000
|
|
|
$0.15
|
|
Natural Gas
|
|
|
Basis Swap
|
|
|
Ventura
|
|
|
2/11 - 12/11
|
|
|
1,670,000
|
|
|
$0.15
|
|
Natural Gas
|
|
|
Basis Swap
|
|
|
Ventura
|
|
|
2/11 - 12/11
|
|
|
835,000
|
|
|
$0.16
|
|
Natural Gas
|
|
|
Basis Swap
|
|
|
Ventura
|
|
|
2/11 - 12/11
|
|
|
3,340,000
|
|
|
$0.16
|
|
Natural Gas
|
|
|
Basis Swap
|
|
|
Ventura
|
|
|
2/11 - 12/11
|
|
|
4,175,000
|
|
|
$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.
|
|
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
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
|
2010
|
|
2009
|
|
|
|
(Dollars in millions)
|
|
Operating revenues
|
|
$
|
79.5
|
|
|
$
|
86.1
|
|
|
$
|
329.8
|
|
|
$
|
307.8
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Purchased natural gas sold
|
|
|
34.3
|
|
|
|
38.8
|
|
|
|
153.9
|
|
|
|
138.8
|
|
Operation and maintenance
|
|
|
13.4
|
|
|
|
20.3
|
|
|
90.6*
|
|
|
63.1
|
|
Depreciation, depletion and amortization
|
|
|
6.6
|
|
|
|
6.8
|
|
|
|
26.0
|
|
|
|
25.5
|
|
Taxes, other than income
|
|
|
3.6
|
|
|
|
2.1
|
|
|
|
13.0
|
|
|
|
11.0
|
|
|
|
|
57.9
|
|
|
|
68.0
|
|
|
|
283.5
|
|
|
|
238.4
|
|
Operating income
|
|
|
21.6
|
|
|
|
18.1
|
|
|
|
46.3
|
|
|
|
69.4
|
|
Earnings
|
|
$
|
12.3
|
|
|
$
|
10.0
|
|
|
$
|
23.2
|
|
|
$
|
37.8
|
|
Transportation volumes (MMdk)
|
|
|
32.1
|
|
|
|
41.1
|
|
|
|
140.5
|
|
|
|
163.3
|
|
Gathering volumes (MMdk)
|
|
|
19.5
|
|
|
|
21.3
|
|
|
|
77.2
|
|
|
|
92.6
|
|
Customer natural gas storage balance (MMdk):
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
|
|
73.8
|
|
|
|
61.0
|
|
|
|
61.5
|
|
|
|
30.6
|
|
Net injection (withdrawal)
|
|
|
(15.0
|
)
|
|
|
.5
|
|
|
|
(2.7
|
)
|
|
|
30.9
|
|
End of period
|
|
|
58.8
|
|
|
|
61.5
|
|
|
|
58.8
|
|
|
|
61.5
|
|
* Reflects a natural gas gathering arbitration charge of $26.6
million ($16.5 million after tax).
|
|
|
Earnings at the pipeline and energy services segment were $23.2 million,
compared to earnings of $37.8 million in 2009. The decrease reflects
higher operation and maintenance expense, lower gathering volumes, as
well as lower volumes transported to storage, partially offset by higher
storage services revenue. Higher operation and maintenance expense is
primarily the result of a natural gas gathering arbitration charge of
$26.6 million ($16.5 million after tax), partially offset by lower costs
related to natural gas storage litigation, largely because of an
insurance recovery. The natural gas storage litigation was settled in
July 2009.
Fourth quarter earnings for 2010 were $12.3 million, compared to
$10.0 million for the comparable prior period. The increase reflects
lower operation and maintenance expense, primarily the result of lower
costs related to natural gas storage litigation, largely because of an
insurance recovery, partially offset by decreased volumes transported to
storage.
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. The company 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 continues to pursue the expansion of its existing natural
gas pipeline in the Bakken production area in northwestern North
Dakota. It is currently soliciting customer interest in a 27 MMcf per
day expansion of capacity out of the area targeted for late 2011.
-
Final agreements have been executed to construct approximately 12
miles of high pressure transmission pipeline providing takeaway
capacity for processed natural gas in northwestern North Dakota. The
project is expected to be completed in the fourth quarter. The company
believes it is in a good position to provide similar services for
other natural gas processing facilities in the area.
-
The company has three natural gas storage fields including the largest
storage field in North America located near Baker, Montana. The
company continues to see strong 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, subject to regulatory approval.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric and Natural Gas Utilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
|
2010
|
|
2009
|
|
|
|
(Dollars in millions, where applicable)
|
|
Operating revenues
|
|
$
|
56.2
|
|
|
$
|
48.5
|
|
|
|
$
|
211.6
|
|
|
$
|
196.2
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Fuel and purchased power
|
|
|
17.8
|
|
|
|
16.6
|
|
|
|
|
63.1
|
|
|
|
65.7
|
|
|
Operation and maintenance
|
|
|
16.8
|
|
|
|
15.4
|
|
|
|
|
63.8
|
|
|
|
60.7
|
|
|
Depreciation, depletion and amortization
|
|
|
7.8
|
|
|
|
6.4
|
|
|
|
|
27.3
|
|
|
|
24.7
|
|
|
Taxes, other than income
|
|
|
2.0
|
|
|
|
1.4
|
|
|
|
|
9.1
|
|
|
|
8.4
|
|
|
|
|
|
44.4
|
|
|
|
39.8
|
|
|
|
|
163.3
|
|
|
|
159.5
|
|
|
Operating income
|
|
|
11.8
|
|
|
|
8.7
|
|
|
|
|
48.3
|
|
|
|
36.7
|
|
|
Earnings
|
|
$
|
6.8
|
|
|
$
|
5.6
|
|
|
|
$
|
28.9
|
|
|
$
|
24.1
|
|
|
Retail sales (million kWh)
|
|
|
728.7
|
|
|
|
688.4
|
|
|
|
|
2,785.7
|
|
|
|
2,663.5
|
|
|
Sales for resale (million kWh)
|
|
|
7.2
|
|
|
|
46.7
|
|
|
|
|
58.3
|
|
|
|
90.8
|
|
|
Average cost of fuel and purchased power per kWh
|
|
$
|
.023
|
|
|
$
|
.022
|
|
|
|
$
|
.021
|
|
|
$
|
.023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
|
2010
|
|
2009
|
|
|
|
(Dollars in millions)
|
|
Operating revenues
|
|
$
|
289.2
|
|
|
$
|
328.0
|
|
|
|
$
|
892.7
|
|
|
$
|
1,072.8
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Purchased natural gas sold
|
|
|
195.0
|
|
|
|
228.6
|
|
|
|
|
589.3
|
|
|
|
757.6
|
|
|
Operation and maintenance
|
|
|
34.6
|
|
|
|
35.2
|
|
|
|
|
137.4
|
|
|
|
140.5
|
|
|
Depreciation, depletion and amortization
|
|
|
10.9
|
|
|
|
10.6
|
|
|
|
|
43.0
|
|
|
|
42.7
|
|
|
Taxes, other than income
|
|
|
12.8
|
|
|
|
13.6
|
|
|
|
|
47.3
|
|
|
|
55.1
|
|
|
|
|
|
253.3
|
|
|
|
288.0
|
|
|
|
|
817.0
|
|
|
|
995.9
|
|
|
Operating income
|
|
|
35.9
|
|
|
|
40.0
|
|
|
|
|
75.7
|
|
|
|
76.9
|
|
|
Earnings
|
|
$
|
23.6
|
|
|
$
|
21.0
|
|
|
|
$
|
37.0
|
|
|
$
|
30.8
|
|
|
Volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
33.9
|
|
|
|
37.4
|
|
|
|
|
95.5
|
|
|
|
102.7
|
|
|
Transportation
|
|
|
37.1
|
|
|
|
37.1
|
|
|
|
|
135.8
|
|
|
|
132.7
|
|
|
Total throughput
|
|
|
71.0
|
|
|
|
74.5
|
|
|
|
|
231.3
|
|
|
|
235.4
|
|
|
Degree days (% of normal)*
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
99
|
%
|
|
|
107
|
%
|
|
|
|
98
|
%
|
|
|
104
|
%
|
|
Cascade
|
|
|
96
|
%
|
|
|
106
|
%
|
|
|
|
96
|
%
|
|
|
105
|
%
|
|
Intermountain
|
|
|
95
|
%
|
|
|
112
|
%
|
|
|
|
100
|
%
|
|
|
107
|
%
|
|
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
|
|
|
The combined utility businesses reported earnings of $65.9 million,
compared to earnings of $54.9 million in 2009. The increase in earnings
reflects higher electric retail sales margins and volumes, an income tax
benefit of $4.8 million, as well as higher nonregulated energy-related
services, partially offset by decreased natural gas retail sales volumes.
Fourth quarter combined utility earnings were $30.4 million, compared to
$26.6 million for the same period in 2009. The earnings increase
reflects an income tax benefit of $4.8 million, as well as higher
electric retail sales margins and volumes. Partially offsetting these
increases were decreased natural gas retail sales volumes and increased
depreciation, depletion and amortization expense.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
The company continues to realize efficiencies and enhanced service
levels through its efforts to standardize operations, share services
and consolidate back-office functions among its four utility companies.
-
In April, the company filed an application with the North Dakota
Public Service Commission for an electric rate increase of
$15.4 million annually, or 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. An interim increase of $7.6 million annually
was effective June 18. In June, a partial settlement agreement was
filed related to cost of capital and capital structure. In July, the
company filed an amendment to its application because of a settlement
agreement providing for separate recovery of the costs associated with
Big Stone II. In November, the company and the NDPSC Advocacy Staff
filed a settlement agreement resolving certain issues. The company
revised its requested 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. A hearing on
the application was held the week of Nov. 8. An order is anticipated
in the first quarter of this year.
-
In August, the company filed an application with the Montana Public
Service Commission for an electric rate increase of $5.5 million
annually, or 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, which is pending before the MTPSC. A
hearing on the application is scheduled for Feb. 28.
-
The company is analyzing potential projects for accommodating load
growth and replacing purchased power contracts with company-owned
generation. The company is reviewing the construction of natural
gas-fired combustion.
-
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 metropolitan 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
project will total approximately $20 million and will include
substation upgrades. Pending regulatory approval, construction is
expected to begin in 2011. The company's customers will not bear any
of the costs associated with the project as costs will be recovered
through an approved interconnect tariff.
-
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 January 2016. 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 with
the upgrade is the best option; however, the company will continue to
review alternatives. The company intends to seek recovery of costs
related to the above matter in electric rates charged to customers.
|
|
|
|
|
|
|
|
Construction
|
|
|
|
|
|
|
|
|
Construction Materials and Contracting
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
2010
|
|
2009
|
|
|
|
(Dollars in millions)
|
|
Operating revenues
|
|
$
|
321.1
|
|
$
|
320.2
|
|
|
|
$
|
1,445.1
|
|
$
|
1,515.1
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
284.0
|
|
|
287.4
|
|
|
|
|
1,260.4
|
|
|
1,292.0
|
|
Depreciation, depletion and amortization
|
|
|
21.1
|
|
|
22.5
|
|
|
|
|
88.3
|
|
|
93.6
|
|
Taxes, other than income
|
|
|
6.8
|
|
|
7.4
|
|
|
|
|
33.4
|
|
|
36.2
|
|
|
|
|
311.9
|
|
|
317.3
|
|
|
|
|
1,382.1
|
|
|
1,421.8
|
|
Operating income
|
|
|
9.2
|
|
|
2.9
|
|
|
|
|
63.0
|
|
|
93.3
|
|
Earnings (loss)
|
|
$
|
3.8
|
|
$
|
(.7
|
)
|
|
|
$
|
29.6
|
|
$
|
47.1
|
|
Sales (000's):
|
|
|
|
|
|
|
|
|
|
|
Aggregates (tons)
|
|
|
5,384
|
|
|
4,979
|
|
|
|
|
23,349
|
|
|
23,995
|
|
Asphalt (tons)
|
|
|
1,203
|
|
|
1,199
|
|
|
|
|
6,279
|
|
|
6,360
|
|
Ready-mixed concrete (cubic yards)
|
|
|
627
|
|
|
720
|
|
|
|
|
2,764
|
|
|
3,042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The construction materials and contracting segment reported earnings of
$29.6 million, compared to $47.1 million for 2009. The decrease in
earnings reflects lower asphalt oil, ready-mixed concrete and asphalt
margins and volumes, as well as decreased construction margins.
Partially offsetting the decreases were lower selling, general and
administrative costs, and higher gains on the sale of property, plant
and equipment.
This segment reported fourth quarter earnings of $3.8 million compared
to a loss of $700,000 for the same period in 2009. The increase in
earnings was largely the result of lower selling, general and
administrative costs, as well as higher gains on the sale of property,
plant and equipment. Partially offsetting these increases were lower
construction and product margins.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
Work backlog as of Dec. 31 was approximately $420 million, with
94 percent of construction backlog being public work and private
representing 6 percent. In the company's peak earnings year of 2006,
private backlog represented 40 percent of construction backlog. Total
backlog at Dec. 31, 2009, was $459 million.
-
Examples of projects in work backlog include several highway paving
projects, airports, bridge work, reclamation and harbor deepening
projects.
-
The company was recently identified as the apparent low bidder on the
Port of Long Beach expansion. Upon final bid approval, the company's
share of the project for this phase is expected to exceed $30 million.
This project is not included in the Dec. 31 backlog.
-
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 and margins to be
comparable to 2010.
-
However, the company has several significant multi-year projects it
will place bids on in 2011 including a light rail project in Hawaii,
work on a Texas military base and a major expansion of a computer chip
manufacture facility in Oregon. The company also expects to place a
new asphalt oil terminal into service in late 2011 in Wyoming.
-
Federal transportation stimulus of $7.9 billion was directed to states
where the company operates. Of that amount, 63 percent was spent as of
year end, with the majority of the remaining $2.9 billion to be spent
during the remainder of 2011.
-
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 38 percent in 2010 as compared to
2006, the peak earnings year for this segment.
-
As the country's 6th 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
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
|
2010
|
|
2009
|
|
|
|
(In millions)
|
|
Operating revenues
|
|
$
|
237.3
|
|
$
|
167.1
|
|
|
$
|
789.1
|
|
$
|
819.0
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
213.6
|
|
|
153.8
|
|
|
|
719.7
|
|
|
736.3
|
|
Depreciation, depletion and amortization
|
|
|
2.9
|
|
|
2.8
|
|
|
|
12.1
|
|
|
12.8
|
|
Taxes, other than income
|
|
|
5.5
|
|
|
4.6
|
|
|
|
23.9
|
|
|
25.7
|
|
|
|
|
222.0
|
|
|
161.2
|
|
|
|
755.7
|
|
|
774.8
|
|
Operating income
|
|
|
15.3
|
|
|
5.9
|
|
|
|
33.4
|
|
|
44.2
|
|
Earnings
|
|
$
|
8.9
|
|
$
|
2.7
|
|
|
$
|
18.0
|
|
$
|
25.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
This segment had earnings of $18.0 million in 2010 compared to
$25.6 million in 2009. This decrease reflects lower construction
workloads and margins in the Western and Central regions, partially
offset by higher workloads and margins in the Mountain region. Lower
general and administrative expenses, including lower payroll-related
costs, also partially offset the earnings decrease.
Fourth quarter earnings for this segment were $8.9 million, compared to
$2.7 million for the comparable prior period. The increase in earnings
was largely the result of higher construction workloads and margins in
the Western region.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
-
Work backlog as of Dec. 31 was approximately $373 million, which is
comparable to the Dec. 31, 2009 backlog, and $56 million higher than
the Sept. 30 backlog of $317 million. 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 31 percent in 2010 as compared to
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
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
|
2010
|
|
2009
|
|
|
|
(In millions)
|
|
Operating revenues
|
|
$
|
.9
|
|
|
$
|
1.4
|
|
|
$
|
7.7
|
|
|
$
|
9.5
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance
|
|
|
(.7
|
)
|
|
|
.6
|
|
|
|
4.8
|
|
|
|
8.1
|
|
|
Depreciation, depletion and amortization
|
|
|
.4
|
|
|
|
.3
|
|
|
|
1.6
|
|
|
|
1.3
|
|
|
Taxes, other than income
|
|
|
.2
|
|
|
|
.1
|
|
|
|
.5
|
|
|
|
.3
|
|
|
|
|
|
(.1
|
)
|
|
|
1.0
|
|
|
|
6.9
|
|
|
|
9.7
|
|
|
Operating income (loss)
|
|
|
1.0
|
|
|
|
.4
|
|
|
|
.8
|
|
|
|
(.2
|
)
|
|
Income from continuing operations
|
|
|
16.0
|
|
|
|
2.5
|
|
|
|
21.0
|
|
|
|
7.3
|
|
|
Loss from discontinued operations, net of tax
|
|
|
(3.3
|
)
|
|
|
---
|
|
|
|
(3.3
|
)
|
|
|
---
|
|
|
Earnings
|
|
$
|
12.7
|
*
|
|
$
|
2.5
|
|
|
$
|
17.7
|
*
|
|
$
|
7.3
|
|
|
* Includes a gain on the sale of the Brazilian transmission lines of
$13.8 million (after tax).
|
|
|
Earnings for the year were $17.7 million, which includes the fourth
quarter gain on the sale of the Brazilian transmission lines of
$13.8 million (after tax), partially offset by a loss from discontinued
operations of $3.3 million (after tax). The loss from discontinued
operations is the result of expenses related to a guarantee of a
construction contract by the domestic power production business, which
was sold in 2007.
Use of Non-GAAP Financial Measures
Where noted in the press
release, 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 a
third quarter 2010 $16.5 million after-tax charge related to an
arbitration ruling, a fourth quarter 2010 $13.8 million after-tax gain
on the sale of its Brazilian transmission lines and a first quarter 2009
$384.4 million after-tax noncash charge related to a "ceiling test"
charge. 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 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.
-
The value of the company's investments in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency exchange rates in countries where the company does
business.
-
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 multi-employer
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, and/or available supplies 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
|
|
|
Twelve Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
|
2010
|
|
2009
|
|
|
|
(In millions, except per share amounts)
(Unaudited)
|
|
Operating revenues
|
|
$
|
1,042.6
|
|
|
$
|
1,016.5
|
|
|
$
|
3,909.7
|
|
|
$
|
4,176.5
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
Fuel and purchased power
|
|
|
17.8
|
|
|
|
16.6
|
|
|
|
63.1
|
|
|
|
65.7
|
|
|
Purchased natural gas sold
|
|
|
185.4
|
|
|
|
219.2
|
|
|
|
567.8
|
|
|
|
739.7
|
|
|
Operation and maintenance
|
|
|
585.5
|
|
|
|
538.6
|
|
|
|
2,375.9
|
|
|
|
2,407.1
|
|
|
Depreciation, depletion and amortization
|
|
|
83.8
|
|
|
|
77.3
|
|
|
|
328.8
|
|
|
|
330.5
|
|
|
Taxes, other than income
|
|
|
39.9
|
|
|
|
37.3
|
|
|
|
163.4
|
|
|
|
166.6
|
|
|
Write-down of natural gas and oil properties
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
620.0
|
|
|
|
|
|
912.4
|
|
|
|
889.0
|
|
|
|
3,499.0
|
|
|
|
4,329.6
|
|
|
Operating income (loss)
|
|
|
130.2
|
|
|
|
127.5
|
|
|
|
410.7
|
|
|
|
(153.1
|
)
|
|
Earnings from equity method investments
|
|
|
23.8
|
|
|
|
2.3
|
|
|
|
30.8
|
|
|
|
8.5
|
|
|
Other income
|
|
|
1.1
|
|
|
|
2.3
|
|
|
|
8.0
|
|
|
|
9.3
|
|
|
Interest expense
|
|
|
21.1
|
|
|
|
21.4
|
|
|
|
83.0
|
|
|
|
84.1
|
|
|
Income (loss) before income taxes
|
|
|
134.0
|
|
|
|
110.7
|
|
|
|
366.5
|
|
|
|
(219.4
|
)
|
|
Income taxes
|
|
|
41.7
|
|
|
|
38.1
|
|
|
|
122.5
|
|
|
|
(96.1
|
)
|
|
Income (loss) from continuing operations
|
|
|
92.3
|
|
|
|
72.6
|
|
|
|
244.0
|
|
|
|
(123.3
|
)
|
|
Loss from discontinued operations, net of tax
|
|
|
(3.3
|
)
|
|
|
---
|
|
|
|
(3.3
|
)
|
|
|
---
|
|
|
Net income (loss)
|
|
|
89.0
|
|
|
|
72.6
|
|
|
|
240.7
|
|
|
|
(123.3
|
)
|
|
Dividends on preferred stocks
|
|
|
.2
|
|
|
|
.1
|
|
|
|
.7
|
|
|
|
.7
|
|
|
Earnings (loss) on common stock
|
|
$
|
88.8
|
|
|
$
|
72.5
|
|
|
$
|
240.0
|
|
|
$
|
(124.0
|
)
|
|
Earnings (loss) per common share - basic:
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) before discontinued operations
|
|
$
|
.49
|
|
|
$
|
.39
|
|
|
$
|
1.29
|
|
|
$
|
(.67
|
)
|
|
Discontinued operations, net of tax
|
|
|
(.02
|
)
|
|
|
---
|
|
|
|
(.01
|
)
|
|
|
---
|
|
|
Earnings (loss) per common share - basic
|
|
$
|
.47
|
|
|
$
|
.39
|
|
|
$
|
1.28
|
|
|
$
|
(.67
|
)
|
|
Earnings (loss) per common share - diluted:
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) before discontinued operations
|
|
$
|
.49
|
|
|
$
|
.38
|
|
|
$
|
1.29
|
|
|
$
|
(.67
|
)
|
|
Discontinued operations, net of tax
|
|
|
(.02
|
)
|
|
|
---
|
|
|
|
(.02
|
)
|
|
|
---
|
|
|
Earnings (loss) per common share - diluted
|
|
$
|
.47
|
|
|
$
|
.38
|
|
|
$
|
1.27
|
|
|
$
|
(.67
|
)
|
|
Dividends per common share
|
|
$
|
.1625
|
|
|
$
|
.1575
|
|
|
$
|
.6350
|
|
|
$
|
.6225
|
|
|
Weighted average common shares outstanding - basic
|
|
|
188.3
|
|
|
|
187.7
|
|
|
|
188.1
|
|
|
|
185.2
|
|
|
Weighted average common shares outstanding - diluted
|
|
|
188.4
|
|
|
|
188.4
|
|
|
|
188.2
|
|
|
|
185.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note: Twelve months ended Dec. 31, 2010 results reflect the effects
of a natural gas gathering arbitration charge of $26.6 million
($16.5 million after tax, or $.09 per common share), as well as a gain
on the sale of the Brazilian transmission assets of $22.7 million ($13.8
million after tax, or $.07 per common share). Twelve months ended
Dec. 31, 2009 results reflect the effects of a $384.4 million after-tax,
or $2.07 per common share, noncash charge relating to the write-down of
natural gas and oil properties.
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data
|
|
|
|
|
|
|
|
|
Book value per common share
|
|
|
|
$
|
14.22
|
|
|
|
$
|
13.61
|
|
|
Market price per common share
|
|
|
|
$
|
20.27
|
|
|
|
$
|
23.60
|
|
|
Dividend yield (indicated annual rate)
|
|
|
|
|
3.2
|
%
|
|
|
|
2.7
|
%
|
|
Price/earnings ratio*
|
|
|
|
|
16.0
|
x
|
|
|
|
N/A
|
|
|
Market value as a percent of book value
|
|
|
|
|
142.5
|
%
|
|
|
|
173.4
|
%
|
|
Return on average common equity*
|
|
|
|
|
9.1
|
%
|
|
|
|
(4.9
|
)%
|
|
Total assets**
|
|
|
|
$
|
6.3
|
|
|
|
$
|
6.0
|
|
|
Total equity**
|
|
|
|
$
|
2.7
|
|
|
|
$
|
2.6
|
|
|
Total debt **
|
|
|
|
$
|
1.5
|
|
|
|
$
|
1.5
|
|
|
Capitalization ratios:
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
|
|
64
|
%
|
|
|
|
63
|
%
|
|
Total debt
|
|
|
|
|
36
|
|
|
|
|
37
|
|
|
|
|
|
|
|
100
|
%
|
|
|
|
100
|
%
|
* Represents 12 months ended
**In billions
MDU Resources Group, Inc.
Financial:
Phyllis A.
Rittenbach, 701-530-1057
Director - Investor Relations
or
Media:
Rick
Matteson, 701-530-1700
Director of Communications and Public Affairs
Copyright © 2012, Business Wire, Inc., All rights reserved. Copyright © 2012, NewsBlaze, Daily News
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