MDU Resources Group Inc : MDU Resources Reports First Quarter Earnings, Reaffirms 2012 Earnings Guidance
04/30/2012| 06:35pm US/Eastern
Recommend:
0
Consolidated earnings of $35.6 million, or 19 cents per share.
Oil production grows 19%.
Rig count reaches 10, up from 2 a year ago.
Recently announced significant Paradox Basin well test results.
Advance Determination of Prudence approved for natural gas plant.
MDU Resources Group, Inc. (NYSE:MDU) today reported first quarter
consolidated earnings of $35.6 million, or 19 cents per common share,
compared to $42.8 million, or 23 cents per common share for the first
quarter of 2011. First quarter 2011 earnings include the effect of an
approximate $4 million benefit related to the favorable resolution of
certain tax matters.
"We achieved the upper range of our guidance for the quarter, even
though we experienced some weather and pricing challenges," said Terry
D. Hildestad, president and chief executive officer of MDU Resources.
"That is a good indication of the strength of our diversified business
and a solid base on which to continue building our estimated $3.7
billion capital growth program over the next five years.
"Our exploration and production business is well on the way toward its
2012 target of increasing oil production by 20 percent to 30 percent
over last year," he said. "Led primarily by growth at Fidelity's Bakken
operations, overall oil production increased to approximately 10,500
barrels per day in the first quarter, a 19 percent increase from the
same period a year earlier."
Fidelity currently is operating 10 rigs, eight more than a year ago.
Five are working in the Bakken, where the company holds approximately
124,000 net leasehold acres, including an additional 27,000 Richland
County acres that were acquired earlier in the first quarter. The
company plans to invest approximately 40 percent of its $400 million
capital budget in its Bakken acreage this year.
Hildestad said that Fidelity is seeing some improvement in Bakken
wellhead oil pricing spreads compared to WTI prices. The price spread
widened in March and negatively affected first quarter earnings but
narrowed in April, and forecasts indicate continued improvement
throughout 2012. Fidelity also was affected by average realized natural
gas prices that were 32 percent lower than the first quarter of 2011.
"In addition, we are excited about the recently announced significant
appraisal well results in the Paradox Basin where we own 75,000 net
leasehold acres," Hildestad said. "The potential of this play appears
substantial. The Cane Creek Unit No. 26-2H well was tested at a
stabilized rate of 647 barrels of oil per day and 561 thousand cubic
feet of natural gas per day following two weeks of production. These
results are based on a significantly restricted flow allowing our team
to properly manage production operations, gather performance data and
minimize natural gas flaring."
Natural gas prices are at a 10-year low and the company's dry natural
gas properties are held by production. The company believes it has been
prudent in curtailing natural gas production in an over-supplied market
and instead focusing on its substantial liquids-based opportunities.
Natural gas prices also had an effect on the pipeline and energy
services business, which experienced decreased storage and gathering
volumes. Total transportation volumes increased, principally related to
completion of a new pipeline to move natural gas from a third-party
processing plant that began operating in December. In addition to a
proposed diesel topping facility, the pipeline business continues to
explore opportunities in other liquid-based midstream projects.
Significantly warmer weather affected sales at the utility business
segment. Natural gas sales volumes declined 12 percent, with
temperatures nearly 31 percent warmer than the prior year in the Plains
states service territory and 11 percent warmer in Idaho. The North
Dakota Public Service Commission recently approved a request for advance
determination of prudence for an 88-MW, approximate $85 million natural
gas generation facility that the company plans to build in North Dakota,
part of the utility's approximate $915 million five-year capital growth
program.
The construction business continued to see signs of stabilization in the
construction market. Earnings at the construction services business
increased to $11.4 million compared to $4.6 million a year ago, driven
by higher construction revenue and margins and higher equipment sales
and rental. Although the construction materials segment experienced a
normal seasonal loss, we are optimistic about the prospects for earnings
from prior green fielded operations in Cheyenne and the Bakken region.
"Our businesses are making good progress in executing their 2012 plans,"
Hildestad said. "We are off to a good start on the year."
Based on the company's projections for the remainder of 2012, annual
earnings guidance is reaffirmed in the range of $1.00 to $1.25 per share.
The company will host a webcast at 11 a.m. EDT on Tuesday, May 1 to
discuss earnings results and guidance. The event can be accessed at www.mdu.com.
Webcast and audio replays will be available. The dial-in number for
audio replay is (855) 859-2056, or (404) 537-3406 for international
callers, conference ID 66804286.
About MDU Resources
MDU Resources Group, Inc., a member of the S&P MidCap 400 index,
provides value-added natural resource products and related services that
are essential to energy and transportation infrastructure, including
regulated utilities and pipelines, exploration and production, and
construction materials and services companies. 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.
Earnings First
Earnings First
Quarter 2012
Quarter 2011
Business Line
(In Millions)
(In Millions)
Exploration and Production
$
12.9
$
16.3
Regulated
Electric and natural gas utilities
33.0
36.0
Pipeline and energy services
2.8
6.9
Construction
Construction materials and contracting
(24.9
)
(21.4
)
Construction services
11.4
4.6
Other
.5
(.1
)
Earnings before discontinued operations
35.7
42.3
Income (loss) from discontinued operations, net of tax
(.1
)
.5
Earnings on common stock
$
35.6
$
42.8
*
* Includes the effect of an approximate $4 million benefit related to
the favorable resolution of certain tax matters.
On a consolidated basis, the following information highlights the key
growth strategies, projections and certain assumptions for the company:
Earnings per common share for 2012, diluted, are projected in the
range of $1.00 to $1.25. The company expects the approximate
percentage of 2012 earnings per common share by quarter to be:
Second quarter - 15 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.
Estimated capital expenditures for 2012 are approximately $700 million.
Exploration and Production
Three Months Ended
March 31,
2012
2011
(Dollars in millions, where applicable)
Operating revenues:
Oil
$
73.4
$
58.6
Natural gas
26.4
45.4
99.8
104.0
Operating expenses:
Operation and maintenance:
Lease operating costs
18.5
18.0
Gathering and transportation
4.3
5.7
Other
9.2
8.3
Depreciation, depletion and amortization
36.8
34.2
Taxes, other than income:
Production and property taxes
9.5
10.1
Other
.4
.3
78.7
76.6
Operating income
21.1
27.4
Earnings
$
12.9
$
16.3
Production:
Oil (MBbls)
957
802
Natural gas (MMcf)
10,047
11,758
Total production (MBOE)
2,632
2,762
Average realized prices (including hedges):
Oil (per barrel)
$
76.71
$
72.98
Natural gas (per Mcf)
$
2.63
$
3.86
Average realized prices (excluding hedges):
Oil (per barrel)
$
84.62
$
79.24
Natural gas (per Mcf)
$
1.94
$
3.39
Average depreciation, depletion and amortization rate, per BOE
$
13.32
$
11.76
Production costs, including taxes, per BOE:
Lease operating costs
$
7.02
$
6.52
Gathering and transportation
1.63
2.05
Production and property taxes
3.62
3.65
$
12.27
$
12.22
Notes:
? Oil includes crude oil, condensate and natural gas liquids.
? Beginning with first quarter results, reporting barrel of oil
equivalents rather than million cubic feet equivalents, based on a
6:1 ratio.
Earnings at this segment were $12.9 million for the first quarter of
2012, compared to $16.3 million in 2011. This decrease reflects 32
percent lower average realized natural gas prices, decreased natural gas
production of 15 percent, as well as higher depreciation, depletion and
amortization expense. These decreases were partially offset by increased
oil production of 19 percent and 5 percent higher average realized oil
prices. The combined oil and natural gas pricing earnings effect was a
negative $6.5 million.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
The company expects to spend approximately $400 million in capital
expenditures in 2012. The company continues its focus on returns by
allocating the majority 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 2012
planned capital expenditure total does not include potential
acquisitions of producing properties.
For 2012, the company expects a 20 percent to 30 percent increase in
oil production and a 12 percent to 20 percent decrease in natural gas
production. The projected decline in natural gas production is
primarily the result of the divestment and/or curtailment of certain
natural gas properties and the deferral of certain natural gas
development activity because of sustained low natural gas prices.
The company has a total of 10 drilling rigs deployed on its acreage in
the Bakken, Texas, Paradox, Heath Shale and other areas. Eight rigs
were deployed at year end. Dependent upon results during 2012, further
growth in rig activity could occur.
Bakken Area
The company owns a total of approximately 124,000 net acres of
leaseholds.
Capital expenditures are expected to total approximately $160
million this year; approximately $60 million higher than the
capital spent for 2011.
Mountrail County, North Dakota
The company owns approximately 16,000 net acres of leaseholds
targeting the middle Bakken and Three Forks formations.
The drilling of 17 operated wells and participation in various
non-operated wells is expected for this year with
approximately $75 million of capital expenditures.
Over 50 future gross well sites have been identified.
Estimated gross ultimate recovery per well is 250,000 to
500,000 Bbls.
Stark County, North Dakota
The company holds approximately 51,000 net exploratory
leasehold acres, targeting the Three Forks formation.
The drilling of 7 operated wells and participation in various
non-operated wells is expected for this year with
approximately $60 million of capital expenditures.
Based on 640-acre spacing, approximately 140 potential gross
well sites have been identified. Estimated gross ultimate
recovery rates per well are 250,000 to 400,000 Bbls.
Richland County, Montana
The company has increased its acreage to approximately
57,000 net exploratory leasehold acres, targeting the Three
Forks formation.
The drilling of 5 operated wells is planned for this year with
approximately $25 million of capital expenditures.
Approximately 100 potential gross well sites have been
identified. Estimated gross ultimate recovery rates per well
are 250,000 to 400,000 Bbls.
Niobrara - southeastern Wyoming
The company holds approximately 65,000 net exploratory leasehold
acres.
The drilling of 4 operated wells is expected for this year with
approximately $25 million of capital expenditures.
Approximately 200 potential gross well sites are available based
on 640-acre spacing.
Paradox Basin - Cane Creek Federal Unit, Utah
The company holds approximately 75,000 net exploratory leasehold
acres.
The company is evaluating its potential in the area and
anticipates increasing the number of wells to be drilled this year
considering recently announced appraisal well results.
Approximately 70 potential gross well sites have been identified.
Estimated gross ultimate recovery rates per well range from
250,000 to 1,000,000 Bbls.
Texas
The company is targeting areas that have the potential for higher
liquids content with approximately $60 million of capital planned
for this year.
Plans are to drill 20 operated wells in Texas this year.
Approximately 50 potential gross well sites have been identified.
Estimated gross ultimate recovery rates per well are 250,000 to
400,000 Bbls.
Heath Shale
The company holds approximately 90,000 net exploratory leasehold
acres in the Heath Shale oil prospect in Montana and expects to
drill 4 wells this year with capital of approximately $20 million.
Other Opportunities
The company continues to pursue acquisitions of additional
leaseholds. Approximately $25 million of capital has been
allocated to leasehold acquisitions, focusing on expansion of
existing positions and new opportunities.
The remaining forecasted 2012 capital has been allocated to other
operated and non-operated opportunities.
Earnings guidance reflects estimated oil and natural gas prices for
May through December as follows:
Crude Oil Index:
NYMEX
$95 to $105 per barrel
Natural Gas Index:
NYMEX
$2.25 to $2.75 per Mcf
Note: Estimated prices do not reflect potential basis differentials.
For the last nine months of 2012, the company has hedged approximately
60 percent to 65 percent of its estimated oil production and
35 percent to 40 percent of its estimated natural gas production. For
2013, the company has hedged 30 percent to 35 percent of its estimated
oil production. The hedges that are in place as of April 30 are
summarized in the following chart:
Forward
Notional
Period
Volume
Price
Commodity
Type
Index
Outstanding
(Bbl/MMBtu)
(Per Bbl/MMBtu)
Crude Oil
Collar
NYMEX
4/12 - 12/12
275,000
$80.00-$87.80
Crude Oil
Collar
NYMEX
4/12 - 12/12
275,000
$80.00-$94.50
Crude Oil
Collar
NYMEX
4/12 - 12/12
275,000
$80.00-$98.36
Crude Oil
Collar
NYMEX
4/12 - 12/12
137,500
$85.00-$102.75
Crude Oil
Collar
NYMEX
4/12 - 12/12
137,500
$85.00-$103.00
Crude Oil
Swap
NYMEX
4/12 - 12/12
137,500
$100.10
Crude Oil
Swap
NYMEX
4/12 - 12/12
137,500
$100.00
Crude Oil
Swap
NYMEX
4/12 - 12/12
275,000
$110.30
Crude Oil
Swap
NYMEX
4/12 - 12/12
275,000
$96.00
Crude Oil
Swap
NYMEX
4/12 - 12/12
275,000
$99.00
Natural Gas
Swap
NYMEX
4/12 - 12/12
2,612,500
$6.27
Natural Gas
Swap
NYMEX
4/12 - 12/12
1,375,000
$5.005
Natural Gas
Swap
NYMEX
4/12 - 12/12
687,500
$5.005
Natural Gas
Swap
NYMEX
4/12 - 12/12
687,500
$5.0125
Natural Gas
Swap
NYMEX
4/12 - 12/12
2,750,000
$3.05
Natural Gas
Swap
Ventura
4/12 - 12/12
2,750,000
$4.87
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
Crude Oil
Collar
NYMEX
1/13 - 12/13
365,000
$90.00-$97.05
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$95.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$95.30
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$100.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$100.02
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$102.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$102.00
Natural Gas
Basis Swap
CIG
4/12 - 12/12
2,062,500
$0.405
Natural Gas
Basis Swap
CIG
4/12 - 12/12
550,000
$0.41
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.
? For all basis swaps, index prices are below NYMEX prices and are
reported as a positive amount in the price column.
Regulated
Electric and Natural Gas Utilities
Electric
Three Months Ended
March 31,
2012
2011
(Dollars in millions, where applicable)
Operating revenues
$
58.0
$
57.8
Operating expenses:
Fuel and purchased power
18.4
16.9
Operation and maintenance
16.2
16.0
Depreciation, depletion and amortization
8.1
8.2
Taxes, other than income
2.7
2.5
45.4
43.6
Operating income
12.6
14.2
Earnings
$
7.5
$
8.5
Retail sales (million kWh)
769.7
794.7
Sales for resale (million kWh)
1.9
6.7
Average cost of fuel and purchased power per kWh
$
.022
$
.020
Natural Gas Distribution
Three Months Ended
March 31,
2012
2011
(Dollars in millions)
Operating revenues
$
307.9
$
370.4
Operating expenses:
Purchased natural gas sold
199.3
257.5
Operation and maintenance
35.3
34.4
Depreciation, depletion and amortization
11.2
11.1
Taxes, other than income
16.1
17.7
261.9
320.7
Operating income
46.0
49.7
Earnings
$
25.5
$
27.5
Volumes (MMdk):
Sales
38.7
43.9
Transportation
37.9
34.1
Total throughput
76.6
78.0
Degree days (% of normal)*
Montana-Dakota
77
%
111
%
Cascade
101
%
103
%
Intermountain
93
%
105
%
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
The combined utility businesses reported earnings of $33.0 million in
the first quarter of 2012, compared to earnings of $36.0 million for the
same period in 2011. This decrease reflects decreased natural gas retail
sales volumes with an approximate earnings affect of $2.6 million,
resulting from warmer weather than last year, lower electric retail
sales volumes as well as higher income taxes, primarily related to the
absence of an income tax benefit of $1.1 million related to favorable
resolution of certain income tax matters in 2011.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
The EPA approved the South Dakota Regional Haze Program on March 29
which requires 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. The company's share of the cost of this air quality control
system is estimated at $125 million. The company intends to seek
recovery of costs related to the above matter in electric rates
charged to customers. The company expects an order for an advance
determination of prudence from the North Dakota Public Service
Commission in the second quarter.
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 necessary to meet the capacity requirements of the
company's integrated electric system 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. On April 11 the
commission issued an order approving the advance determination of
prudence.
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. A project the company is currently engaged on is a 30-mile
natural gas line into the Hanford Nuclear Site in Washington.
Currently the company is involved with a number of pipeline 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 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 company's portion
of the project totals approximately $18 million and includes
substation upgrades. Construction is underway and the transmission
project is expected to be completed by the third quarter.
Pipeline and Energy Services
Three Months Ended
March 31,
2012
2011
(Dollars in millions)
Operating revenues
$
49.6
$
74.0
Operating expenses:
Purchased natural gas sold
16.0
34.1
Operation and maintenance
17.1
17.6
Depreciation, depletion and amortization
6.2
6.4
Taxes, other than income
3.5
3.6
42.8
61.7
Operating income
6.8
12.3
Earnings
$
2.8
$
6.9
Transportation volumes (MMdk)
32.0
27.3
Gathering volumes (MMdk)
14.2
17.5
Customer natural gas storage balance (MMdk):
Beginning of period
36.0
58.8
Net withdrawal
(8.7
)
(25.9
)
End of period
27.3
32.9
This segment reported first quarter earnings of $2.8 million, compared
to earnings of $6.9 million for the same period in 2011. This decrease
reflects lower storage services revenue, lower gathering volumes, as
well as the absence of an income tax benefit of $500,000 related to
favorable resolution of certain income tax matters in 2011.
The following information highlights the key growth strategies,
projections and certain assumptions for this segment:
In February, the company and Calumet Refining, LLC signed a letter of
intent to explore the feasibility of jointly building and operating a
20,000 barrel per day diesel topping plant in southwestern North
Dakota. The facility would process Bakken crude and market the diesel
within the Bakken region. Site selection, permitting, crude oil feed
procurement, marketing and engineering studies are currently underway.
The company has recently seen an uptick in natural gas moving to
storage and expects average balances for the remainder of the year to
be comparable to last year. The divestment and/or curtailment of
certain natural gas properties and the deferral of certain gas
development activity are expected to result in gathering volumes being
lower in 2012 compared to last year. The decline is expected to be
partially offset by higher transportation volumes related to growth
projects placed in service in the Bakken area.
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.
Installation of additional compression at the Charbonneau station was
completed and placed into service in September, providing additional
firm capacity for producers in the Bakken production area. With some
additional modifications, this project has the potential of adding a
total of 27 MMcf of firm capacity.
Construction has begun on approximately 13 miles of high pressure
transmission pipeline from the Stateline processing facilities in
northwestern North Dakota to deliver gas into the Northern Border
Pipeline. The project is expected to be completed by mid 2012.
Construction
Construction Materials and Contracting
Three Months Ended
March 31,
2012
2011
(Dollars in millions)
Operating revenues
$
149.4
$
143.5
Operating expenses:
Operation and maintenance
157.0
146.8
Depreciation, depletion and amortization
19.8
21.5
Taxes, other than income
8.0
7.7
184.8
176.0
Operating loss
(35.4
)
(32.5
)
Loss
$
(24.9
)
$
(21.4
)
Sales (000's):
Aggregates (tons)
2,493
2,827
Asphalt (tons)
100
165
Ready-mixed concrete (cubic yards)
468
397
Construction Services
Three Months Ended
March 31,
2012
2011
(In millions)
Operating revenues
$
218.2
$
203.4
Operating expenses:
Operation and maintenance
187.9
184.9
Depreciation, depletion and amortization
2.8
2.9
Taxes, other than income
7.8
7.7
198.5
195.5
Operating income
19.7
7.9
Earnings
$
11.4
$
4.6
The combined construction businesses reported a first quarter loss of
$13.5 million, compared to a loss of $16.8 million a year ago. The
decreased loss reflects a $6.8 million earnings increase at the services
group that resulted from higher workloads and margins in the Central and
Western regions and higher equipment sales and rental and Mountain
region margins. Partially offsetting the service group's increased
earnings was a seasonal loss at the materials group including lower
aggregate margins and volumes. In addition, the construction businesses
on a combined basis had an increase in income taxes primarily related to
the absence of an income tax benefit of $2.5 million related to
favorable resolution of certain income tax matters in 2011.
The following information highlights the key growth strategies,
projections and certain assumptions for the construction segments:
The construction materials work backlog as of March 31 was
approximately $532 million, compared to approximately $569 million a
year ago. The March 31 backlog at construction services was
approximately $333 million, compared to approximately $347 million a
year ago. The backlog includes a variety of projects such as highway
paving projects, airports, bridge work, reclamation, harbor
expansions, substation and line construction, solar and other
commercial, institutional and industrial projects including refinery
work.
The company's operations in the prolific Bakken area of North Dakota
currently have approximately $35 million of backlog.
Projected revenues included in the company's 2012 earnings guidance
are in the range of $1.3 billion to $1.4 billion for construction
materials and $750 million to $850 million for construction services.
The company anticipates margins in 2012 to be higher than 2011 levels
at construction materials and construction services.
The company continues to pursue opportunities for expansion in energy
projects such as refineries, transmission, substations, utility
services, solar, wind towers, and geothermal. Initiatives are aimed at
capturing additional market share and expansion into new markets.
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.
Other
Three Months Ended
March 31,
2012
2011
(In millions)
Operating revenues
$
2.1
$
2.5
Operating expenses:
Operation and maintenance
1.3
2.9
Depreciation, depletion and amortization
.5
.4
Taxes, other than income
--
.1
1.8
3.4
Operating income (loss)
.3
(.9
)
Income (loss) from continuing operations
.5
(.1
)
Income (loss) from discontinued operations, net of tax
(.1
)
.5
Earnings
$
.4
$
.4
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 exploration and 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 materials and contracting
and construction services 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.
Initiatives to reduce greenhouse gas emissions could adversely impact
the company's electric generation operations.
The company is subject to government regulations that may delay and/or
have a negative impact on its business and its results of operations
and cash flows. Statutory and regulatory requirements also may limit
another party's ability to acquire the company.
Weather conditions can adversely affect the company's operations 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.
The company's operations may be negatively impacted by cyber attacks
or acts of terrorism.
Other factors that could cause actual results or outcomes for the
company to differ materially from those discussed in forward-looking
statements include:
Acquisition, disposal and impairments of assets or facilities.
Changes in operation, performance and construction of plant
facilities or other assets.
Changes in present or prospective generation.
The ability to obtain adequate and timely cost recovery for the
company's regulated operations through regulatory proceedings.
The availability of economic expansion or development
opportunities.
Population growth rates and demographic patterns.
Market demand for, available supplies of, and/or costs of, energy-
and construction-related products and services.
The cyclical nature of large construction projects at certain
operations.
Changes in tax rates or policies.
Unanticipated project delays or changes in project costs,
including related energy costs.
Unanticipated changes in operating expenses or capital
expenditures.
Labor negotiations or disputes.
Inability of the various contract counterparties to meet their
contractual obligations.
Changes in accounting principles and/or the application of such
principles to the company.
Changes in technology.
Changes in legal or regulatory proceedings.
The ability to effectively integrate the operations and the
internal controls of acquired companies.
The ability to attract and retain skilled labor and key personnel.
Increases in employee and retiree benefit costs and funding
requirements.
For a further discussion of these risk factors and cautionary
statements, refer to Item 1A - Risk Factors in the company's most recent
Form 10-K.
MDU Resources Group, Inc.
Three Months Ended
March 31,
2012
2011
(In millions, except per share amounts)
(Unaudited)
Operating revenues
$
852.8
$
901.8
Operating expenses:
Fuel and purchased power
18.4
16.9
Purchased natural gas sold
185.4
244.7
Operation and maintenance
444.5
427.7
Depreciation, depletion and amortization
85.4
84.7
Taxes, other than income
48.0
49.7
781.7
823.7
Operating income
71.1
78.1
Earnings from equity method investments
1.2
.5
Other income
1.1
1.9
Interest expense
19.4
22.1
Income before income taxes
54.0
58.4
Income taxes
18.1
15.9
*
Income from continuing operations
35.9
42.5
Income (loss) from discontinued operations, net of tax
(.1
)
.5
Net income
35.8
43.0
Dividends declared on preferred stocks
.2
.2
Earnings on common stock
$
35.6
$
42.8
Earnings per common share - basic:
Earnings before discontinued operations
$
.19
$
.22
Discontinued operations, net of tax
--
.01
Earnings per common share - basic
$
.19
$
.23
Earnings per common share - diluted:
Earnings before discontinued operations
$
.19
$
.22
Discontinued operations, net of tax
--
.01
Earnings per common share - diluted
$
.19
$
.23
Dividends declared per common share
$
.1675
$
.1625
Weighted average common shares outstanding - basic
188.8
188.7
Weighted average common shares outstanding - diluted
189.2
188.8
* Including the effect of an approximate $4 million benefit related to
the favorable resolution of certain tax matters.
Three Months Ended
March 31,
2012
2011
(Unaudited)
Other Financial Data
Book value per common share
$
14.61
$
14.16
Market price per common share
$
22.39
$
22.97
Dividend yield (indicated annual rate)
3.0
%
2.8
%
Price/earnings ratio*
20.7x
17.9x
Market value as a percent of book value
153.3
%
162.2
%
Return on average common equity*
7.5
%
9.1
%
Total assets**
$
6.5
$
6.2
Total equity**
$
2.8
$
2.7
Total debt **
$
1.4
$
1.4
Capitalization ratios:
Total equity
66
%
65
%
Total debt
34
35
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 or Laura
Lueder, corporate public relations manager, 701-530-1095
Recommend:
