EX-99 2 exhibit99.htm EXHIBIT 99 WebFilings | YE Earnings News Release 2012








MDU Resources Reports 2012 Results, Initiates Guidance for 2013

•
Construction businesses post 47 percent earnings growth year-over-year.
•
Grew total liquids production 29 percent in 2012 – oil production, excluding natural gas liquids, up 36 percent.
•
Oil reserve replacement ratio of 267 percent.
•
Utility electric customer counts grew 9 percent in Bakken.
•
Substantial progress made on proposed diesel topping plant.
•
Initial earnings guidance for 2013 of $1.20 to $1.35 per common share.

BISMARCK, N.D. - Feb. 4, 2013 - MDU Resources Group, Inc. (NYSE:MDU) announced a consolidated loss for 2012 of $1.4 million, or 1 cent per common share, compared to 2011 earnings of $212.3 million, or $1.12 per share. Adjusted earnings were $216.8 million, or $1.15 per common share for 2012 compared to 2011 adjusted earnings of $225.2 million, or $1.19 per share. Refer to the Non-GAAP Financial Measures and Reconciliation of GAAP to Adjusted Earnings section beginning on page 15 of this press release.

The company reported a consolidated loss for the fourth quarter of $61.2 million, or 32 cents per share, compared to 2011 fourth quarter earnings of $60.8 million or 32 cents per share. Adjusted earnings were $76.0 million, or 40 cents per common share, compared to $73.9 million, or 39 cents per share in 2011.

"Our businesses are strong and our 2012 adjusted earnings reflect it," said David L. Goodin, president and CEO of MDU Resources. "Our construction businesses are seeing markets improve with earnings growth of 47 percent compared to last year."

The construction businesses reported their highest annual earnings since 2009 with 2012 earnings totaling $70.8 million, up $22.8 million from last year. The construction materials business saw an increase in the private construction market and a strengthening of markets in the Intermountain and North Central regions, as well as higher ready-mixed concrete and asphalt oil margins and volumes. The construction services business also saw strong growth, with record earnings at its inside electric business in Oregon and its specialty equipment manufacturing and rental business. The combined construction business backlog at year-end was approximately $731 million, $39 million higher than a year ago.




The exploration and production business, like many independent companies in the sector, uses the full-cost method of accounting. Under this method, the company is required to perform a quarterly ceiling test comparing its capitalized costs to the after-tax, discounted expected cash flow from its economic proved oil and natural gas reserves. The price used in the test is based on the average of the trailing 12 months. This test resulted in total after-tax write-downs for the year of $246.8 million. The write-downs were largely driven by the lower natural gas price environment in 2012. Other factors affecting the write-downs include certain capital associated with non-economic 2012 exploratory activity. The write-downs are noncash and do not affect cash flows.

“In the fourth quarter, net of the noncash write-down, our exploration and production business reported its highest quarterly earnings since 2009," Goodin said. "The group increased annual oil production by 36 percent over the prior year, outperforming its target.”

Led by success with its Bakken and Paradox activity, company oil production for the fourth quarter was 1.1 million barrels of oil, a 59 percent increase from 2011. The company is continuing to rebalance its production portfolio, with total liquids accounting for approximately 52 percent of production in the fourth quarter, up from 34 percent a year ago. Oil alone represented 44 percent of production compared to 26 percent last year.

The company plans to invest approximately $400 million on the exploration and production business in 2013, with a significant portion of the capital allocated to development areas. The company currently has five rigs drilling in the Bakken, one in Paradox and one in Texas.

At the electric utility, earnings were $1.4 million higher driven by strong customer and sales growth largely in the North Dakota Bakken oil play. Electric retail sales increased 4 percent overall, and 6 percent in North Dakota. To help serve this growing customer load and meet other needs, the utility is entering 2013 with a record capital budget of $252 million. The electric utility expects to begin construction this year of an $86 million, 88-megawatt natural gas turbine to be completed in late 2014. The utility also will contribute about $125 million toward installation of a new emission control system at the Big Stone generating plant, which it co-owns. The system installation is expected to be complete in 2015.

The natural gas distribution business experienced lower natural gas deliveries with a warmer than normal heating season. Temperatures ranged from 6 percent warmer than last year in the Pacific Northwest to 16 percent warmer in the Plains with earnings down $9.0 million for the year.

Total transportation volumes at the pipeline and energy services business increased 22 percent year-over-year, largely because of agreements to build and operate takeaway pipelines serving several new natural gas processing facilities. Transportation to storage also grew by 30 percent. Dry natural gas gathering volumes declined 31 percent as low natural gas prices led customers to shift production strategies.

The pipeline and energy services business continued to focus on growing its midstream energy business. The company has made substantial progress in conjunction with Calumet Refining on the proposed building and operation of a diesel topping plant that would refine 20,000 barrels per day of Bakken crude oil. The permitting process has progressed with the public comment period related to the air quality permit concluding today. In addition, a certificate of convenience and public necessity has been signed by the North Dakota Public Service Commission approving the company's utility business to supply electric power to the proposed facility.


2


Last May, the pipeline and energy services business purchased a 50 percent interest in a new natural gas processing plant and related facilities. Production has been ramping up and the company will receive a full year of ownership and ensuing benefits in 2013.

"Our businesses have a strong foundation for growth, and we expect to build on the momentum that we experienced throughout 2012," Goodin said. "We are excited about the opportunities we are pursuing and are committed to continue growing our company with a capital budget of $3.8 billion between 2013 and 2017, including $807 million in 2013. Accordingly, building off of our 2012 adjusted earnings results of $1.15 per share, we are establishing our 2013 guidance in the range of $1.20 to $1.35 per common share."

The company will host a webcast at 11 a.m. EST Feb. 5 to discuss 2012 earnings results and 2013 guidance. The event can be accessed at www.mdu.com. A webcast replay and audio replay will be available. The dial-in number for audio replay is (855) 859-2056, or (404) 537-3406 for international callers, conference ID 85150168.

About MDU Resources

MDU Resources Group, Inc., a member of the S&P MidCap 400 index, provides value-added natural resource products and related services that are essential to energy and transportation infrastructure, including regulated utilities and pipelines, exploration and production, and construction materials and services. For more information about MDU Resources, see the company's website at www.mdu.com or contact the Investor Relations Department at investor@mduresources.com.

Contacts

Financial:
Phyllis A. Rittenbach, director - investor relations, (701) 530-1057

Media:
Rick Matteson, director of communications and public affairs, (701) 530-1700
Laura Lueder, corporate public relations manager, (701) 530-1095

3


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.
Business Line
2012
Earnings
(In Millions)
2011
Earnings
(In Millions)
2012
Fourth
Quarter
Earnings
(In Millions)
2011
Fourth
Quarter
Earnings
(In Millions)
Exploration and Production 

$69.6

 

$80.3

 

$25.5

 

$20.2

 
Regulated
 
 
 
 
 
 
 
 
Electric and natural gas utilities
60.0

 
67.6

 
26.7

 
27.8

 
Pipeline and energy services
11.6

 
23.1

 
4.7

 
6.2

 
Construction Materials and Services
70.8

 
48.0

 
16.2

 
15.5

 
Other
4.8

 
6.2

 
2.9

 
4.2

 
Earnings before discontinued operations, noncash write-downs of oil and natural gas properties and net benefit related to natural gas gathering operations litigation
216.8

 
225.2

 
76.0

 
73.9

 
Income (loss) from discontinued operations, net of tax*
13.6

 
(12.9
)
 
8.7

 
(13.1
)
 
Effects of noncash write-downs of oil and natural gas properties
(246.8
)
 
—

 
(145.9
)
 
—

 
Net benefit related to natural gas gathering operations litigation
15.0

 
—

 
—

 
—

 
Earnings (loss) on common stock

($1.4
)
 

$212.3

 

($61.2
)
 

$60.8

 
 
 
 
 
 
 
 
 
 
* Reflects a 2012 reversal of a 2011 arbitration charge of $13.0 million after tax related to a guarantee of a construction contract.

On a consolidated basis, the following information highlights the key growth strategies, projections and certain assumptions for the company:

•
Earnings per common share for 2013, diluted, are projected in the range of $1.20 to $1.35. The company expects the approximate percentage of 2013 earnings per common share by quarter to be:
•
First quarter – 15 percent.
•
Second quarter – 20 percent.
•
Third quarter – 35 percent.
•
Fourth quarter – 30 percent.
•
The company's long-term compound annual growth goals on earnings per share from operations are in the range of 7 to 10 percent.

4


•
The company continually seeks opportunities to expand through organic growth opportunities and strategic acquisitions.
•
The company focuses on creating value through vertical integration between its business units. For example, the pipeline and energy services business' proposed partially owned diesel topping plant located in the Bakken region, expects to have the construction materials and services business involved in constructing the facility, the exploration and production business supplying production to the plant, the pipeline transporting natural gas to the plant, and the utility supplying electricity.
•
Capital expenditures for 2012 and estimated capital expenditures for 2013 through 2017 are noted in the following table.

Business Line
Capital
Expenditures
2012 Actual
(In Millions)
Capital
Expenditures
2013 Estimated*
(In Millions)
Capital
Expenditures
2013 - 2017
Total Estimated*
(In Millions)
Exploration and Production

$554

 

$400

 

$2,127

 
Regulated
 
 
 
 
 
 
Electric
112

 
154

 
496

 
Natural gas distribution
130

 
98

 
498

 
Pipeline and energy services**
134

 
105

 
435

 
Construction
 
 
 
 
 
 
Construction materials and contracting
45

 
43

 
241

 
Construction services
15

 
13

 
67

 
Other
1

 
2

 
10

 
Net proceeds and other
(57
)
 
(8
)
 
(26
)
 
Total Capital Expenditures

$934

 

$807

 

$3,848

 
 
 
 
 
 
 
 
* Capital expenditures relative to potential acquisitions of businesses would be incremental to these estimates.
** 2012 includes the Pronghorn acquisition. 2013 includes the company's estimated share of certain capital related to the proposed diesel topping plant project.


5


Exploration and Production

 
Three Months Ended
 
Twelve Months Ended
 
December 31,
 
December 31,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions, where applicable)
Operating revenues:
 
 
 
 
 
 
 
Oil
$
100.6

 
$
63.7

 
$
319.6

 
$
236.1

Natural gas liquids
8.4

 
12.4

 
33.0

 
41.9

Natural gas
25.4

 
40.0

 
96.0

 
175.6

 
134.4

 
116.1

 
448.6

 
453.6

Operating expenses:
 
 
 
 
 
 
 
Operation and maintenance:
 
 
 
 
 
 
 
Lease operating costs
19.6

 
19.8

 
77.7

 
75.6

Gathering and transportation
4.6

 
6.2

 
17.4

 
24.3

Other
8.6

 
9.2

 
37.0

 
36.5

Depreciation, depletion and amortization
48.0

 
36.6

 
160.7

 
142.6

Taxes, other than income:
 
 
 
 
 
 
 
Production and property taxes
11.8

 
10.3

 
39.7

 
40.8

Other
.2

 
.1

 
1.0

 
—

Write-downs of oil and natural gas properties
231.7

 
—

 
391.8

 
—

 
324.5

 
82.2

 
725.3

 
319.8

Operating income (loss)
(190.1
)
 
33.9

 
(276.7
)
 
133.8

Earnings (loss)
$
(120.4
)
 
$
20.2

 
$
(177.2
)
 
$
80.3

Production:
 
 
 
 
 
 
 
Oil (MBbls)
1,139

 
718

 
3,694

 
2,724

Natural gas liquids (MBbls)
218

 
215

 
828

 
776

Natural gas (MMcf)
7,538

 
10,931

 
33,214

 
45,598

Total production (MBOE)
2,614

 
2,754

 
10,058

 
11,099

Average realized prices (including hedges):
 
 
 
 
 
 
 
Oil (per barrel)
$
88.29

 
$
88.81

 
$
86.52

 
$
86.66

Natural gas liquids (per barrel)
$
38.39

 
$
57.62

 
$
39.81

 
$
54.06

Natural gas (per Mcf)
$
3.37

 
$
3.66

 
$
2.89

 
$
3.85

Average realized prices (excluding hedges):
 
 
 
 
 
 
 
Oil (per barrel)
$
84.27

 
$
91.84

 
$
84.84

 
$
91.62

Natural gas liquids (per barrel)
$
38.39

 
$
57.62

 
$
39.81

 
$
54.06

Natural gas (per Mcf)
$
2.80

 
$
2.86

 
$
2.08

 
$
3.30

Average depreciation, depletion and amortization rate, per BOE
$
17.70

 
$
12.72

 
$
15.28

 
$
12.25

Production costs, including taxes, per BOE:
 
 
 
 
 
 
 
Lease operating costs
$
7.50

 
$
7.18

 
$
7.73

 
$
6.81

Gathering and transportation
1.76

 
2.25

 
1.73

 
2.19

Production and property taxes
4.53

 
3.72

 
3.94

 
3.67

 
$
13.79

 
$
13.15

 
$
13.40

 
$
12.67

Notes:
 
 
 
 
• Oil includes crude oil and condensate; natural gas liquids are reflected separately.
• Results are reported in barrel of oil equivalents based on a 6:1 ratio.

6


 
2012
 
2011
 
Oil
Natural Gas Liquids
Natural Gas
 
Oil
Natural Gas Liquids
Natural Gas
 
(MBbls/MMcf)
Production by region:
 
 
 
 
 
 
 
Rocky Mountain
3,295

249

23,180

 
2,290

199

34,472

Mid-Continent/Gulf States*
399

579

10,034

 
434

577

11,126

Total production
3,694

828

33,214

 
2,724

776

45,598

* Includes Offshore Gulf of Mexico.
 
Oil
Natural Gas Liquids
Total Oil and Natural Gas Liquids Production
 
Total % Change from Prior Quarter
 
(MBbls)
 
 
Production by quarter:
 
 
 
 
 
Fourth Quarter 2011
718

215

933

 
—
First Quarter 2012
767

190

957

 
3%
Second Quarter 2012
876

209

1,085

 
13%
Third Quarter 2012
912

211

1,123

 
4%
Fourth Quarter 2012
1,139

218

1,357

 
21%

Earnings at this segment were $69.6 million for 2012, excluding the effects of the noncash write-downs of $246.8 million after tax, compared to earnings of $80.3 million in 2011. The decrease reflects 25 percent lower average realized natural gas prices, 27 percent lower natural gas production in part because of voluntary curtailments and divestments, higher depreciation, depletion and amortization expense, as well as lower average realized natural gas liquids prices of 26 percent. These decreases were partially offset by increased oil production of 36 percent, as well as lower gathering and transportation expense.

Fourth quarter earnings were $25.5 million, excluding the effect of a $145.9 million after-tax noncash write-down, compared to 2011 fourth quarter earnings of $20.2 million. This increase reflects increased oil production of 59 percent, largely related to drilling activity in the Bakken and Paradox Basin areas. This increase was partially offset by decreased natural gas production of 31 percent, higher depreciation, depletion and amortization expense, as well as lower average realized natural gas liquids and natural gas prices of 33 percent and 8 percent, respectively.

The company's oil additions in 2012 were 9.9 MMBOE, a 267 percent replacement of oil production. Natural gas liquids adds were 1.8 MMBOE, or 219 percent of natural gas liquids production, and natural gas adds were 18.4 Bcf, or 55 percent of natural gas production. Total adds were 14.8 MMBOE with a reserve replacement ratio of 147 percent, absent revisions. For 2012, the company had negative natural gas reserve revisions of 123 Bcf primarily a result of significantly lower natural gas prices compared to last year. Therefore, total reserves dropped from 97.7 MMBOE at year-end 2011 to 80.5 MMBOE at year-end 2012.

The following information highlights the key growth strategies, projections and certain assumptions for this segment:


7


•
The company expects to spend approximately $400 million in capital expenditures in 2013. With improving well cost efficiencies and having essentially completed the extensive 2012 exploration program, the capital program will focus on growth projects where the company expects higher returns namely the Bakken, Paradox Basin and Texas, as described below. Follow-up on development activity of the 2012 exploration program (beyond the activity in the Paradox) could take place in late 2013 or early 2014 depending upon the economic competitiveness of those plays once they are fully appraised. The 2013 planned capital expenditure total does not include potential acquisitions.
•
For 2013, the company expects a 25 to 30 percent increase in oil production, a flat to slight increase in natural gas liquids production, and a 15 to 25 percent decrease in natural gas production. The majority of the capital program is focused on growing oil production considering current relative commodity prices. The company expects to return to some natural gas development when the commodity prices make it more profitable to do so.
•
The company has a total of seven drilling rigs deployed on its acreage in the Bakken, Texas and Paradox areas.
•
Bakken areas
◦
The company owns a total of approximately 127,000 net acres of leaseholds in Mountrail, Stark and Richland counties.
◦
Production grew 71 percent in the fourth quarter compared to last year.
◦
Capital expenditures are expected to total approximately $200 million in 2013. The company is currently operating five rigs in the play; with improving drilling efficiencies and other factors that number could vary across the year from three to five rigs.
◦
Following are recent well results:
Well Name
Spacing
1st Production Date
24-Hour IP Rate (BOEPD)
Sundts 23-14-15H
1280
10/27/2012
1,494
Corpron 16-21-22H
1280
11/16/2012
1,395
Miriah 19-30-29H
1280
11/29/2012
972
Bauer 25-36H
1280
12/20/2012
1,290
Niemitalo 24-13H
1280
1/7/2013
1,071
State 34-33-28H
1280
1/9/2013
1,053
Fladeland 34-31H
640
1/13/2013
642

•
Paradox Basin, Utah
◦
The company has increased its holding to approximately 83,000 net acres and also has an option to lease another 20,000 acres.
◦
Production grew more than 1,400 percent in the fourth quarter compared to last year.
◦
The company has experienced strong well results with the Paradox 12-1 consistently producing 1,500 BOPD since mid-September with consistently high-flowing pressures above 2,000 psi.
◦
The company is continuing to proceed systematically in this play, and anticipates spending $70 million of capital expenditures in 2013. As the play is fully understood, the opportunity to ramp up to full-scale development could increase the planned investment. At this point, the potential appears very significant.
◦
Approximately 50 to 75 future net locations have been identified. Estimated gross ultimate recovery rates per well range from 250,000 to 1 million barrels.

8


•
Texas
◦
The company is targeting areas that have the potential for higher liquids content with approximately $40 million of capital planned for this year.
•
Other opportunities
◦
The company plans to drill one horizontal well during 2013 in Sioux County, Neb. Upon evaluation of this well, the company may exercise an option to purchase a 65 percent working interest in approximately 79,000 gross acres.
◦
The remaining forecasted 2013 capital has been allocated to other operated and non-operated opportunities.
•
Earnings guidance reflects estimated average NYMEX index prices for February through December in the ranges of $85 to $95 per barrel of crude oil, and $3.25 to $3.75 per Mcf of natural gas. Estimated prices for natural gas liquids are in the range of $30 to $45 per barrel.
•
For 2013 the company has hedged 7,000 BOPD, with an additional 1,000 BOPD for the period March through December, utilizing swaps and costless collars with a weighted average price of $99.01 and $92.50/$107.03 (floor/ceiling) respectively. For 2013, the company has hedged 30,000 MMBtu of natural gas per day, with an additional 10,000 MMBtu per day for February through December and an additional 10,000 MMBtu per day for March through December, utilizing swaps at a weighted average price of $3.74.
•
The hedges that are in place as of Feb. 4 are summarized in the following chart:
Commodity
Type
Index
Period
Outstanding
Forward Notional Volume
(Bbl/MMBtu)
Price
(Per Bbl/MMBtu)
Crude Oil
Collar
NYMEX
1/13 - 12/13
365,000
$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
365,000
$102.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
365,000
$104.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
365,000
$98.00
Crude Oil
Swap
NYMEX
3/13 - 12/13
153,000
$94.15
Crude Oil
Swap
NYMEX
3/13 - 12/13
153,000
$94.00
Natural Gas
Swap
NYMEX
1/13 - 12/13
3,650,000
$3.76
Natural Gas
Swap
NYMEX
1/13 - 12/13
3,650,000
$3.90
Natural Gas
Swap
NYMEX
1/13 - 12/13
3,650,000
$4.00
Natural Gas
Swap
NYMEX
2/13 - 12/13
3,340,000
$3.50
Natural Gas
Swap
NYMEX
3/13 - 12/13
3,060,000
$3.50
Natural Gas
Swap
NYMEX
1/14 - 12/14
3,650,000
$4.13

9


Regulated
Electric and Natural Gas Utilities

Electric
 
 
 
 
Three Months Ended
 
Twelve Months Ended
 
December 31,
 
December 31,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions, where applicable)
Operating revenues
$
62.5

 
$
55.7

 
$
236.9

 
$
225.5

Operating expenses:
 
 
 

 
 
 
 
Fuel and purchased power
21.1

 
15.7

 
72.4

 
64.5

Operation and maintenance
18.6

 
17.8

 
71.8

 
70.3

Depreciation, depletion and amortization
8.4

 
8.0

 
32.5

 
32.2

Taxes, other than income
2.5

 
2.0

 
10.3

 
9.4

 
50.6

 
43.5

 
187.0

 
176.4

Operating income
11.9

 
12.2

 
49.9

 
49.1

Earnings
$
7.6

 
$
7.6

 
$
30.6

 
$
29.2

Retail sales (million kWh)
806.7

 
750.7

 
2,996.5

 
2,878.9

Sales for resale (million kWh)
2.3

 
.1

 
14.1

 
63.9

Average cost of fuel and purchased power per kWh
$
.025

 
$
.020

 
$
.023

 
$
.021

 
 
 
 
 
 
 
 
Natural Gas Distribution
 
 
 
 
Three Months Ended
 
Twelve Months Ended
 
December 31,
 
December 31,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions)
Operating revenues
$
250.0

 
$
280.0

 
$
754.8

 
$
907.4

Operating expenses:
 
 
 
 
 
 
 
Purchased natural gas sold
157.3

 
185.8

 
457.4

 
594.6

Operation and maintenance
36.5

 
34.9

 
139.4

 
137.3

Depreciation, depletion and amortization
11.7

 
11.2

 
45.7

 
44.6

Taxes, other than income
11.5

 
12.3

 
44.7

 
48.0

 
217.0

 
244.2

 
687.2

 
824.5

Operating income
33.0

 
35.8

 
67.6

 
82.9

Earnings
$
19.1

 
$
20.2

 
$
29.4

 
$
38.4

Volumes (MMdk):
 
 
 

 
 
 
 
Sales
33.7

 
33.6

 
93.8

 
103.3

Transportation
37.3

 
36.5

 
132.0

 
124.2

Total throughput
71.0

 
70.1

 
225.8

 
227.5

Degree days (% of normal)*
 
 
 
 
 
 
 
Montana-Dakota/Great Plains
99
%
 
85
%
 
84
%
 
101
%
Cascade
91
%
 
101
%
 
96
%
 
103
%
Intermountain
90
%
 
102
%
 
91
%
 
107
%
* Degree days are a measure of the daily temperature-related demand for energy for heating.


10


The combined utility businesses reported earnings of $60.0 million, compared to earnings of $67.6 million in 2011. This decrease reflects lower natural gas retail sales volumes resulting from warmer weather than last year as well as increased operation and maintenance expense. These decreases were partially offset by higher electric retail sales volumes of 4 percent.

Fourth quarter combined utility earnings were $26.7 million, compared to $27.8 million for the same period in 2011. The decrease in earnings resulted from higher operation and maintenance expense, including higher payroll and benefit-related costs, as well as increased depreciation, depletion and amortization expense. These decreases were partially offset by higher electric retail sales volumes of 7 percent.

The following information highlights the key growth strategies, projections and certain assumptions for this segment:

•
The company filed an application with the South Dakota Public Utilities Commission on Dec. 21 for a natural gas rate increase requesting a total of $1.5 million annually or approximately 3.3 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, a region operations building, automated meter reading and new customer billing system.
•
The company filed an application with the Montana Public Service Commission on Sept. 26 for a natural gas rate increase requesting a total of $3.5 million annually or approximately 5.9 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, the landfill gas production facility, a region operations building, automated meter reading and new customer billing system. The company requested an interim increase of $1.7 million or approximately 2.9 percent. A hearing has been scheduled for May 1.
•
The EPA approved the South Dakota Regional Haze Program, 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 for the installation is estimated at $125 million and is expected to be complete in 2015. The North Dakota Public Service Commission has approved advance determination of prudence for recovery of costs related to this system in electric rates charged to customers.
•
The company plans to construct and operate an 88-MW simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $86 million and a projected in-service date in late 2014. It will be located on owned property that is adjacent to the company's Heskett Generating Station near Mandan, N.D. The capacity is necessary to meet the requirements of the company's integrated electric system customers and will be a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the NDPSC.
•
The company plans to invest approximately $70 million in 2013 to serve the growing electric and natural gas customer base associated with the Bakken oil development in western North Dakota and eastern Montana.
•
The company expects to grow its rate base by approximately 6 percent compounded annually over the next five years.
•
The company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors, with company- and customer-owned pipeline facilities designed to serve existing facilities served by fuel oil or propane, and to serve new customers. The company is currently engaged in a 30-mile natural gas line project into the Hanford Nuclear Site in Washington.

11


•
Currently the company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho.
•
The company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted toward delivery of energy to major market areas.

Pipeline and Energy Services
 
 
 
 
 
 
 
Three Months Ended
 
Twelve Months Ended
 
 
December 31,
 
December 31,
 
 
2012

 
2011

 
2012

 
2011

 
 
(Dollars in millions)
 
Operating revenues
$
51.6

 
$
62.9

 
$
193.1

 
$
278.3

 
Operating expenses:
 
 
 
 
 
 
 
 
Purchased natural gas sold
15.1

 
25.6

 
50.5

 
125.3

 
Operation and maintenance
17.3

 
16.1

 
52.2

*
68.9

 
Depreciation, depletion and amortization
7.3

 
6.2

 
27.7

 
25.5

 
Taxes, other than income
3.2

 
2.9

 
13.6

 
13.2

 
 
42.9

 
50.8

 
144.0

 
232.9

 
Operating income
8.7

 
12.1

 
49.1

 
45.4

 
Earnings
$
4.7

 
$
6.2

 
$
26.6

*
$
23.1

 
Transportation volumes (MMdk)
34.8

 
30.7

 
137.7

 
113.2

 
Natural gas gathering volumes (MMdk)
10.6

 
15.7

 
47.1

 
66.5

 
Customer natural gas storage balance (MMdk):
 
 
 
 
 
 
 
 
Beginning of period
49.2

 
38.5

 
36.0

 
58.8

 
Net injection (withdrawal)
(5.5
)
 
(2.5
)
 
7.7

 
(22.8
)
 
End of period
43.7

 
36.0

 
43.7

 
36.0

 
* Results reflect a net benefit of $24.1 million ($15.0 million after tax) related to natural gas gathering operations litigation, largely reflected in operation and maintenance expense.

Earnings at the pipeline and energy services segment were $26.6 million, compared to earnings of $23.1 million in 2011. The earnings increase includes a net benefit of $15.0 million after tax related to natural gas gathering operations litigation. This increase was partially offset by lower natural gas gathering volumes from existing operations, as well as an impairment of certain natural gas gathering assets of $1.7 million after tax.

Fourth quarter earnings for 2012 were $4.7 million, compared to $6.2 million for the comparable prior period. This earnings decrease reflects lower natural gas gathering volumes from existing operations, partially offset by higher oil and natural gas gathering and processing volumes from a recent acquisition.

The following information highlights the key growth strategies, projections and certain assumptions for this segment:

•
The company along with Calumet Refining, LLC, continue to explore the feasibility of 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. Land has been purchased near Dickinson, N.D., for the site, and permitting activities are under way. Total project costs are estimated to be approximately $280 million to $300 million, with a projected in-service date in late 2014.

12


•
In May, the company purchased a 50 percent undivided interest in Whiting Oil and Gas Corp.'s Pronghorn natural gas and oil midstream assets near Belfield, N.D., in the Bakken area. The company invested approximately $100 million in 2012 including the purchase price. The Belfield natural gas processing plant has an inlet processing capacity of 35 MMcf per day. The company will receive a full year of benefit from this acquisition in 2013.
•
In August the company placed in service approximately 13 miles of high-pressure transmission pipeline from the Stateline processing facilities in northwestern North Dakota to deliver natural gas into the Northern Border Pipeline, which is expected to result in increased transportation volumes for 2013.
•
Dry natural gas gathering volumes are expected to be lower in 2013 compared to 2012 because of curtailments and the deferral of certain development activity.
•
The company recently reached an agreement to construct a pipeline in 2014 to connect the planned Garden Creek II gas processing plant in northwestern North Dakota to deliver natural gas into the Northern Border Pipeline.
•
The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Montana, North Dakota and Wyoming, is expanding, most notably the Bakken area 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.

Construction

Construction Materials and Contracting
 
 
 
 
Three Months Ended
 
Twelve Months Ended
 
December 31,
 
December 31,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions)
Operating revenues
$
375.9

 
$
371.7

 
$
1,617.4

 
$
1,510.0

Operating expenses:
 
 
 
 
 
 
 
Operation and maintenance
339.2

 
325.6

 
1,442.5

 
1,337.4

Depreciation, depletion and amortization
19.6

 
21.2

 
79.5

 
85.5

Taxes, other than income
8.0

 
7.4

 
37.5

 
36.0

 
366.8

 
354.2

 
1,559.5

 
1,458.9

Operating income
9.1

 
17.5

 
57.9

 
51.1

Earnings
$
7.7

 
$
9.7

 
$
32.4

 
$
26.4

Sales (000's):
 
 
 

 
 
 
 
Aggregates (tons)
5,302

 
6,234

 
23,285

 
24,736

Asphalt (tons)
1,114

 
1,240

 
5,988

 
6,709

Ready-mixed concrete (cubic yards)
747

 
783

 
3,157

 
2,864



13


Construction Services
 
 
 
 
 
 
Three Months Ended
 
Twelve Months Ended
 
December 31,
 
December 31,
 
2012

 
2011

 
2012

 
2011

 
(In millions)
Operating revenues
$
249.1

 
$
226.7

 
$
938.6

 
$
854.4

Operating expenses:
 
 
 

 
 
 
 
Operation and maintenance
225.4

 
207.3

 
831.9

 
778.5

Depreciation, depletion and amortization
2.8

 
2.9

 
11.1

 
11.4

Taxes, other than income
6.9

 
6.3

 
29.1

 
25.4

 
235.1

 
216.5

 
872.1

 
815.3

Operating income
14.0

 
10.2

 
66.5

 
39.1

Earnings
$
8.5

 
$
5.8

 
$
38.4

 
$
21.6


The combined construction businesses reported earnings of $70.8 million, compared to earnings of $48.0 million in 2011. The earnings increase reflects higher workloads and margins in the Central and Western regions, higher margins in the Mountain Region and higher equipment sales and rental margins at the services group, as well as higher ready-mixed concrete and asphalt oil margins and volumes at the materials group. Partially offsetting these increases were lower gains on the sale of property, plant and equipment and lower aggregate margins and volumes at the materials business.

Fourth quarter earnings for the combined construction businesses were $16.2 million, compared to $15.5 million for the comparable prior period. The construction businesses reported lower income taxes, as well as higher workloads and margins in the Central and Mountain regions and higher equipment sales and rental margins at the services group, and higher ready-mixed concrete margins at the materials group. Partially offsetting these increases were lower construction margins and lower gains on the sale of property, plant and equipment at the materials group. In addition, the construction businesses on a combined basis reported higher selling, general and administrative costs, largely payroll-related.

The following information highlights the key growth strategies, projections and certain assumptions for the construction segments:

•
The construction materials work backlog as of Dec. 31 was approximately $406 million, compared to approximately $384 million a year ago. Private work represents 14 percent of the backlog, up from 8 percent a year ago. Public work represents 86 percent of the backlog. The Dec. 31 backlog at construction services was approximately $325 million, compared to approximately $308 million a year ago. The backlogs include a variety of projects such as highway paving projects, airports, bridge work, reclamation, harbor expansions, substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.
•
The company's backlog in the Bakken area of North Dakota is approximately $33 million.
•
Projected revenues included in the company's 2013 earnings guidance are in the range of $1.5 billion to $1.7 billion for construction materials and $850 million to $950 million for construction services.
•
The company anticipates margins in 2013 to be higher compared to 2012.
•
The company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, substations, utility services, solar, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expanding into new markets.
•
As the country's fifth-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.

14


Other

 
Three Months Ended
 
Twelve Months Ended
 
 
December 31,
 
December 31,
 
2012

 
2011

 
2012

 
2011

 
 
(In millions)
 
Operating revenues
$
3.4

 
$
3.5

 
$
10.4

 
$
11.4

 
Operating expenses:
 
 
 
 
 
 
 
 
Operation and maintenance
(1.0
)
 
(1.8
)
 
3.3

 
4.7

 
Depreciation, depletion and amortization
.5

 
.4

 
2.0

 
1.6

 
Taxes, other than income
—

 
—

 
.2

 
.1

 
 
(0.5
)
 
(1.4
)
 
5.5

 
6.4

 
Operating income
3.9

 
4.9

 
4.9

 
5.0

 
Income from continuing operations
2.9

 
4.2

 
4.8

 
6.2

 
Income (loss) from discontinued operations, net of tax
8.7

 
(13.1
)
 
13.6

 
(12.9
)
 
Earnings (loss)
$
11.6

 
$
(8.9
)
 
$
18.4

 
$
(6.7
)
 

Earnings were $18.4 million for the year compared to a loss of $6.7 million in 2011. Income from discontinued operations in 2012 reflects a benefit of a $13.0 million after-tax reversal resulting from a favorable court ruling on an arbitration charge that was recorded in 2011. The arbitration charge related to a guarantee of a construction contract at the domestic power production business, which was sold in 2007.

Fourth quarter earnings were $11.6 million compared to a loss of $8.9 million in the comparable prior period. Income from discontinued operations in 2012 reflects the previously discussed arbitration charge reversal, which was partially offset by the reversal of estimated insurance recoveries related to this matter that were recorded in the second quarter of 2012.

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 reflects an adjustment to exclude a fourth quarter 2012 $145.9 million after-tax, or 77 cents per common share, noncash ceiling test write-down, a third quarter 2012 $100.9 million after-tax, or 54 cents per common share, noncash ceiling test write-down, as well as an adjustment to exclude a second quarter 2012 reversal of an arbitration charge of $15.0 million after tax, or 8 cents per common share. 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.

15


Reconciliation of GAAP to Adjusted Earnings

 
2012
Earnings
2011
Earnings
2012
EPS
2011
EPS
 
(In millions, except per share amounts)
Earnings (loss) on common stock
$
(1.4
)
 
$
212.3

 
$
(.01
)
 
$
1.12

 
Discontinued operations
(13.6
)
 
12.9

 
(.07
)
 
.07

 
Noncash write-downs of oil and natural gas properties
246.8

 
—

 
1.31

 
—

 
Net benefit related to natural gas gathering operations litigation
(15.0
)
 
—

 
(.08
)
 
—

 
Adjusted earnings
$
216.8

 
$
225.2

 
$
1.15

 
$
1.19

 

 
Fourth
Quarter
2012
Earnings
Fourth
Quarter
2011
Earnings
Fourth
Quarter
2012
EPS
Fourth
Quarter
2011
EPS
 
(In millions, except per share amounts)
Earnings (loss) on common stock
$
(61.2
)
 
$
60.8

 
$
(.32
)
 
$
.32

 
Discontinued operations
(8.7
)
 
13.1

 
(.05
)
 
.07

 
Noncash write-downs of oil and natural gas properties
145.9

 
—

 
.77

 
—

 
Net benefit related to natural gas gathering operations litigation
—

 
—

 
—

 
—

 
Adjusted earnings
$
76.0

 
$
73.9

 
$
.40

 
$
.39

 

Risk Factors and Cautionary Statements that May Affect Future Results

The information in this release includes certain forward-looking statements, including earnings per share guidance and statements by the president and CEO of MDU Resources, within the meaning of Section 21E of the Securities Exchange Act of 1934. Although the company believes that its expectations are based on reasonable assumptions, actual results may differ materially. Following are important factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements.
•
The company’s exploration and production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, that are subject to various external influences that cannot be controlled.
•
The regulatory approval, permitting, construction, startup and 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.

16


•
The company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the company’s control. If the company is unable to obtain economic financing in the future, the company’s ability to execute its business plans, make capital expenditures or pursue acquisitions that the company may otherwise rely on for future growth could be impaired. As a result, the market value of the company’s common stock may be adversely affected. If the company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders.
•
The company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the company’s customers and counterparties.
•
The backlogs at the company’s construction materials and contracting and construction services businesses are subject to delay or cancellation and may not be realized.
•
Actual quantities of recoverable oil, natural gas liquids and natural gas reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. There is a risk that changes in estimates of proved reserve quantities or other factors including downward movements in prices, could result in additional future noncash write-downs of the company's oil and natural gas properties.
•
The company’s operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the company to environmental liabilities.
•
Initiatives to reduce greenhouse gas emissions could adversely impact the company’s operations.
•
The company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party’s ability to acquire the company.
•
Weather conditions can adversely affect the company’s operations, 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.

17


◦
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.

18


MDU Resources Group, Inc.
 
 
 
 
Three Months Ended
 
Twelve Months Ended
 
December 31,
 
December 31,
 
2012

 
2011

 
2012

 
2011

 
(In millions, except per share amounts)
 
(Unaudited)
Operating revenues
$
1,081.1

 
$
1,065.7

 
$
4,075.4

 
$
4,050.5

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased power
21.1

 
15.7

 
72.4

 
64.5

Purchased natural gas sold
146.2

 
175.9

 
425.2

 
572.2

Operation and maintenance
649.2

 
619.7

 
2,631.5

 
2,491.1

Depreciation, depletion and amortization
98.3

 
86.5

 
359.2

 
343.4

Taxes, other than income
44.1

 
41.3

 
176.1

 
172.9

Write-downs of oil and natural gas properties
231.7

 
—

 
391.8

 
—

 
1,190.6

 
939.1

 
4,056.2

 
3,644.1

Operating income (loss)
(109.5
)
 
126.6

 
19.2

 
406.4

Earnings from equity method investments
1.4

 
2.4

 
5.4

 
4.7

Other income
2.6

 
1.4

 
6.6

 
6.5

Interest expense
19.8

 
19.7

 
76.7

 
81.4

Income (loss) before income taxes
(125.3
)
 
110.7

 
(45.5
)
 
336.2

Income taxes
(55.6
)
 
36.6

 
(31.2
)
 
110.3

Income (loss) from continuing operations
(69.7
)
 
74.1

 
(14.3
)
 
225.9

Income (loss) from discontinued operations, net of tax
8.7

 
(13.1
)
 
13.6

 
(12.9
)
Net income (loss)
(61.0
)
 
61.0

 
(.7
)
 
213.0

Dividends declared on preferred stocks
.2

 
.2

 
.7

 
.7

Earnings (loss) on common stock
$
(61.2
)
 
$
60.8

 
$
(1.4
)
 
$
212.3

 
 
 
 
 
 
 
 
Earnings (loss) per common share – basic:
 
 
 
 
 
 
 
Earnings (loss) before discontinued operations
$
(.37
)
 
$
.39

 
$
(.08
)
 
$
1.19

Discontinued operations, net of tax
.05

 
(.07
)
 
.07

 
(.07
)
Earnings (loss) per common share – basic
$
(.32
)
 
$
.32

 
$
(.01
)
 
$
1.12

Earnings (loss) per common share – diluted:
 
 
 
 
 
 
 
Earnings (loss) before discontinued operations
$
(.37
)
 
$
.39

 
$
(.08
)
 
$
1.19

Discontinued operations, net of tax
.05

 
(.07
)
 
.07

 
(.07
)
Earnings (loss) per common share – diluted
$
(.32
)
 
$
.32

 
$
(.01
)
 
$
1.12

Dividends declared per common share
$
.1725

 
$
.1675

 
$
.6750

 
$
.6550

Weighted average common shares outstanding – basic
188.8

 
188.8

 
188.8

 
188.8

Weighted average common shares outstanding – diluted
188.8

 
188.9

 
188.8

 
188.9


Note: Three months ended Dec. 31, 2012 results reflect the effects of a $145.9 million after-tax noncash write-down of oil and natural gas properties. Twelve months ended Dec. 31, 2012 results reflect the effects of noncash write-downs of oil and natural gas properties of $246.8 million after tax, as well as the effects of a net benefit of $24.1 million ($15.0 million after tax) related to natural gas gathering operations litigation. Three months ended Dec. 31, 2012 discontinued operations reflect the effects of a benefit related to the reversal of an arbitration charge of $21.0 million ($13.0 million after tax) related to a guarantee of a construction contract, which was partially offset by the reversal of estimated insurance recoveries related to this matter that were recorded in the second quarter of 2012. Twelve months ended Dec. 31, 2012 discontinued operations reflect the effects of a benefit related to the reversal of an arbitration charge, as previously discussed. Three months and 12 months ended Dec. 31, 2011 discontinued operations reflect the effects of an arbitration charge of $21.0 million ($13.0 million after tax), as previously discussed.

19




Twelve Months Ended
 
December 31,
 
2012

 
2011

 
(Unaudited)
 
 
 
 
Other Financial Data
 
 
 
Book value per common share
$
13.95

 
$
14.62

Market price per common share
$
21.24

 
$
21.46

Dividend yield (indicated annual rate)
3.2
 %
 
3.1
%
Price/earnings ratio*
***

 
19.2
x
Market value as a percent of book value
152.3
 %
 
146.8
%
Return on average common equity*
-0.1
 %
 
7.8
%
Net operating cash flow**
$
585

 
$
627

Total assets**
$
6,682

 
$
6,556

Total equity**
$
2,648

 
$
2,776

Total debt **
$
1,773

 
$
1,425

Capitalization ratios:
 
 
 
Total equity
60
 %
 
66
%
Total debt
40

 
34

 
100
 %
 
100
%
    *    Represents 12 months ended
  **    In millions
***    Not meaningful because of effects of 2012 noncash write-downs of $246.8 million after tax


20