EX-99 2 exhibit99.htm EXHIBIT 99 WebFilings | 3Q Earnings News Release 2012



MDU Resources Reports Third Quarter Earnings

•
Construction group earnings improve by 36%; backlog increases $55 million.
•
Earnings increase by 32% at electric utility with 8% customer growth in Bakken area.
•
E&P segment reaches weekly oil production record in October averaging approx. 13,500 barrels per day; up from 3rd quarter average of 12,200 barrels per day.

BISMARCK, N.D. – Oct. 31, 2012 – MDU Resources Group, Inc. (NYSE:MDU) today reported third quarter consolidated earnings of $71.1 million, or 38 cents per share, excluding the effect of a noncash ceiling test write-down at its exploration and production group primarily related to lower natural gas prices. This is an earnings per share increase of 12 percent compared to third quarter 2011 earnings per share of 34 cents. Comparative earnings were $63.8 million. Including the noncash write-down the company reported a consolidated loss of $29.8 million, or 16 cents per share for third quarter 2012.

"We had a good quarter. With the strength of our diversified group of companies, we were able to generate solid earnings growth for the quarter even though we realized lower natural gas and oil prices than the prior year," MDU Resources president and CEO Terry D. Hildestad said. "Our construction businesses continued to experience upward momentum increasing earnings by 36 percent over last year, and our utility business had another solid quarter driven in part by further growth in the Bakken." Hildestad added, "We experienced some delays in planned drilling during the third quarter, however we are seeing strong recent results from wells coming on line late third quarter and so far in the fourth quarter. That positions us well to meet our oil production projected increase of 25 to 30 percent this year."

The construction materials and services businesses had combined earnings of $51.8 million, an increase of $13.6 million over last year. Growth in construction workloads and margins and improved volumes and margins in most material product lines, as well as higher equipment sales and rental margins and the company's lower cost structure contributed to the earnings increase. Revenues improved 6 percent and earnings 36 percent. This group has a backlog that is $55 million higher compared to a year earlier, and the mix of construction materials backlog has improved with private work now representing 17 percent, up from 8 percent a quarter earlier.

Electric utility earnings grew by 32 percent over the prior-year third quarter to $11.0 million, in large part because of a 5 percent increase in electric sales and lower operating expenses. The utility continues to benefit from continued economic growth in northwestern North Dakota's Bakken oil fields where the company saw an 8 percent increase in its electric customer count compared to a year ago. The natural gas business reported a normal seasonal loss, which was an approximate 20 percent improvement compared to the third quarter of 2011, related to decreased operating expenses. In September, the company filed an application with the Montana Public Service Commission for a natural gas rate increase of $3.5 million annually, or 5.9 percent, to cover costs associated with investments in facilities.


1


The pipeline and energy services business reported earnings of $3.3 million, compared to $5.2 million a year ago, principally because of lower natural gas gathering volumes from producers responding to the low price environment. However, higher storage services revenue was experienced for the quarter and this group has continued to position itself for future growth. The company is focused on further expanding in the midstream space with its investment earlier this year in the Pronghorn facilities and by recently exercising an option to purchase land for the proposed diesel topping plant in the Bakken area.

The company's exploration and production business' strategy of shifting its focus to oil production to take advantage of pricing economics while targeting a more balanced commodity portfolio resulted in oil production increasing by 19 percent compared to the same period last year, even with delays experienced in bringing certain Bakken and Paradox wells on line. However, those wells were brought on production in late September and October contributing to a company weekly oil production record in October averaging approximately 13,500 barrels of oil per day, compared to a third quarter average production of 12,200 barrels of oil per day. Higher oil production partially offset the effects of lower commodity prices for the quarter with average realized prices for natural gas and oil 20 percent and 5 percent lower, respectively, compared to a year earlier. Including the Bakken and Paradox areas, the company's inventory of oil-based drilling locations continue to provide significant opportunities for sustainable growth for this business.

Like many independent exploration and production companies, the company's E&P business 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. At the end of the third quarter, a $100.9 million after-tax write-down was recorded as a result of this test largely driven by a decline in the trailing 12 month average natural gas price. The write-down is noncash and does not affect cash flows.

Hildestad said, "With strong recent well results and improved recent oil pricing differentials in the Bakken, this group is positioned for solid performance this final quarter of the year and beyond." Hildestad noted that growth initiatives at the company's utility and pipeline segments are on track with the utility seeing solid customer growth driven by Bakken activity. "We are pleased with our improved results at our construction businesses. With the fourth quarter being a shoulder period for the construction materials business, how the weather holds out will be the key determining factor for results for the final months of this year. Weather was on our side in the fourth quarter a year ago. As we look beyond 2012 we see positive indicators for our construction businesses considering housing starts and construction activity are up, our backlog is higher and we have a new two-year federal highway bill in place," Hildestad added.

The company updated 2012 earnings guidance to a range of $1.05 to $1.20 per share excluding the third quarter noncash write-down and the benefit from the arbitration charge reversal recorded in the second quarter. This compares to previous guidance of $1.00 to $1.25 per share. Including the noncash write-down and the benefit from the arbitration charge reversal, earnings guidance is 60 cents to 75 cents per share.

Conference Call

The company will webcast its third quarter earnings conference call beginning at 11 a.m. EDT Nov. 1; the call will be accessible 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 34753792.


2


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 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
Earnings Third Quarter 2012
(In Millions)
Earnings Third Quarter 2011
(In Millions)
Exploration and Production 

$13.1

 

$22.5

 
Regulated
 
 
 
 
Electric and natural gas utilities
2.2

 
(2.9
)
 
Pipeline and energy services
3.3

 
5.2

 
Construction Materials and Services
51.8

 
38.2

 
Other
.8

 
.9

 
Earnings before discontinued operations and noncash write-down
71.2

 
63.9

 
Loss from discontinued operations, net of tax
(.1
)
 
(.1
)
 
Effects of noncash write-down
(100.9
)
 
—

 
Earnings (loss) on common stock

($29.8
)
 

$63.8

 

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 are projected in the range of $1.05 to $1.20, excluding a third quarter noncash write-down of $100.9 million after tax and a second quarter $15.0 million after-tax benefit from a reversal of an arbitration charge. Including these items, earnings guidance for 2012 is 60 cents to 75 cents per common share.
•
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 to 10 percent.
•
The company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.
•
Estimated capital expenditures for 2012 are approximately $940 million.

4


Exploration and Production

 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions, where applicable)
Operating revenues:
 
 
 
 
 
 
 
Oil
$
85.0

 
$
74.9

 
$
243.6

 
$
201.9

Natural gas
23.5

 
45.9

 
70.6

 
135.6

 
108.5

 
120.8

 
314.2

 
337.5

Operating expenses:
 
 
 
 
 
 
 
Operation and maintenance:
 
 
 
 
 
 
 
Lease operating costs
20.7

 
19.4

 
58.2

 
55.8

Gathering and transportation
4.3

 
6.9

 
12.8

 
18.1

Other
9.6

 
9.8

 
28.4

 
27.3

Depreciation, depletion and amortization
41.4

 
38.5

 
112.6

 
106.0

Taxes, other than income:
 
 
 
 
 
 
 
Production and property taxes
9.6

 
10.0

 
27.8

 
30.5

Other
.2

 
(.7
)
 
.8

 
(.1
)
Write-down of oil and natural gas properties
160.1

 
—

 
160.1

 
—

 
245.9

 
83.9

 
400.7

 
237.6

Operating income (loss)
(137.4
)
 
36.9

 
(86.5
)
 
99.9

Earnings (loss)
$
(87.8
)
 
$
22.5

 
$
(56.9
)
 
$
60.1

Production:
 
 
 
 
 
 
 
Oil (MBbls)
1,123

 
944

 
3,165

 
2,567

Natural gas (MMcf)
7,390

 
11,656

 
25,676

 
34,667

Total production (MBOE)
2,354

 
2,887

 
7,444

 
8,345

Average realized prices (including hedges):
 
 
 
 
 
 
 
Oil (per barrel)
$
75.69

 
$
79.28

 
$
76.96

 
$
78.64

Natural gas (per Mcf)
$
3.17

 
$
3.94

 
$
2.75

 
$
3.91

Average realized prices (excluding hedges):
 
 
 
 
 
 
 
Oil (per barrel)
$
73.89

 
$
80.90

 
$
76.45

 
$
83.05

Natural gas (per Mcf)
$
2.25

 
$
3.44

 
$
1.88

 
$
3.44

Average depreciation, depletion and amortization rate, per BOE
$
16.85

 
$
12.72

 
$
14.44

 
$
12.09

Production costs, including taxes, per BOE:
 
 
 
 
 
 
Lease operating costs
$
8.77

 
$
6.71

 
$
7.81

 
$
6.68

Gathering and transportation
1.84

 
2.37

 
1.72

 
2.17

Production and property taxes
4.07

 
3.46

 
3.74

 
3.66

 
$
14.68

 
$
12.54

 
$
13.27

 
$
12.51

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.


5


Earnings at this segment were $13.1 million for the third quarter of 2012, excluding the effect of a $100.9 million after-tax noncash write-down, compared to $22.5 million in 2011. The decrease reflects 37 percent lower natural gas production in part because of voluntary curtailments and divestments, 20 percent lower average realized natural gas prices, 5 percent lower average realized oil prices, as well as higher depreciation, depletion and amortization expense. These decreases were partially offset by increased oil production of 19 percent, as well as lower gathering and transportation expense.

Contributing to the average realized oil price decrease were significantly wider Bakken wellhead pricing spreads relative to WTI prices compared to last year. Earlier this year the Bakken price spread widened dramatically; however, since then the company has seen continual improvement and forecasts indicate a significant improvement in the fourth quarter.

The increase in DD&A is the result of a higher rate, largely the result of lower proved natural gas reserves. Lower natural gas and natural gas liquids prices have resulted in the removal of proved undeveloped reserves, as well as some late-life proved developed producing reserves, from the company's total proved reserve calculations. These reserves remain in the ground and can be reinstated as proved reserves once prices improve and the company is committed to developing the reserves.

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

•
The company has increased its expected capital expenditures to approximately $525 million in 2012. The company has improved efficiencies across its portfolio to reduce individual well costs. However, an increase in the number of total planned wells for the year as well as the drilling of higher working interest wells has resulted in higher total projected capital expenditures for the year. The company continues its focus on returns by allocating the majority of its capital investment into the production of oil given the current commodity price environment.
•
For 2012, the company expects a 25 to 30 percent increase in oil production and a 25 to 30 percent decrease in natural gas production. The projected decline in natural gas production is primarily the result of a decision to curtail certain natural gas properties as well as divestments and the deferral of certain natural gas development activity because of sustained low natural gas prices.
•
The company has a total of seven drilling rigs deployed on its acreage in the Bakken, Texas and Paradox areas.
•
Bakken Area
◦
The company owns a total of approximately 127,000 net acres of leaseholds in Mountrail, Stark and Richland counties.
◦
Capital expenditures are now expected to total approximately $265 million this year; an expansion of $165 million compared to 2011. The increase in the Bakken projected capital expenditures from earlier this year relates to more operated wells being drilled in 2012 along with the drilling of higher working-interest wells.
◦
Mountrail County, N.D.
▪
The company has had strong recent well results in the area. The Amundson 23-14H (15 percent working interest) came on production Oct. 16 with a 24-hour initial production rate of 1,353 barrels of oil and 582 Mcf of natural gas and the Luke 19-20-29H (58 percent WI) began producing Oct. 18 at a 24-hour IP rate of 968 barrels and 678 Mcf.
▪
Approximately 40 remaining middle Bakken locations have been identified. This does not include any additional Three Forks potential, which is currently being evaluated. Estimated gross ultimate recovery rates per well are 250,000 to 600,000 barrels.

6


◦
Stark County, N.D.
▪
The company has had strong recent well results in the Pavlish 19-20H (71 percent WI) and Kudrna 5-8H (81 percent WI) with 24-hour IP rates of 1,097 barrels of oil and 657 Mcf of natural gas, and 1,151 barrels of oil and 571 Mcf, respectively. The Pavlish came on production on Sept. 19 and the Kudrna Sept. 20.
▪
Based on current information and assuming 1,280-acre spacing, the company has identified approximately 40 future drill sites. Estimated gross ultimate recovery rates per well are 200,000 to 400,000 barrels.
◦
Richland County, Mont.
▪
On Sept. 30, the company brought the Klose (66 percent WI) well on line with a 24-hour IP rate of 371 barrels of oil and 82 Mcf of natural gas.
▪
Approximately 100 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 barrels.
◦
Paradox Basin--Cane Creek Federal Unit, Utah
▪
The company holds approximately 75,000 net exploratory leasehold acres.
▪
The drilling of six operated wells is planned for this year with approximately $45 million of capital expenditures.
▪
The company has experienced strong well results with the Cane Creek 12-1 (100 percent WI) consistently producing approximately 1,500 barrels of oil per day excluding natural gas over the past three weeks with consistently high flowing pressures.
▪
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.
◦
Texas
▪
The company is targeting areas that have the potential for higher liquids content with approximately $65 million of capital planned for this year.
▪
Approximately 50 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 barrels.
◦
Heath Shale
▪
The company holds approximately 90,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana and expects to spend approximately $40 million this year.
▪
Two recently completed wells have had IP rates in excess of 200 barrels per day. Production optimization efforts continue in the Heath with ongoing cleanouts of the horizontal laterals and paraffin treatment to assure sustainable production from the field.
◦
Sioux County, Nebraska
▪
The company has entered into an exploration agreement where it will drill two vertical wells and one horizontal well. The vertical wells in the project have been drilled and are undergoing selective well testing. The horizontal well is planned for the first half of next year. After evaluating these initial wells, the company may exercise an option to purchase a 65 percent working interest in approximately 79,000 gross acres.
◦
Other Opportunities
▪
The company has spent approximately $25 million in the Niobrara area where the economic viability and other horizons are currently being evaluated.
▪
The remaining forecasted 2012 capital has been allocated to other operated and non-operated opportunities, including $25 million for acquisitions of leaseholds acquired earlier this year primarily in the Bakken, Richland County area.
•
Earnings guidance reflects estimated average NYMEX index prices for November and December in the ranges of $90 to $95 per barrel of crude oil and $3.00 to $3.50 per Mcf of natural gas. Estimated prices do not reflect potential basis differentials.

7


•
For the last three months of 2012, the company has hedged 8,000 barrels of oil per day utilizing swaps and costless collars at a weighted average price of $101.34 and $81.25/$95.88 (floor/ceiling) respectively, and 49,500 MMBtu of natural gas per day utilizing swaps at a weighted average price of $4.38.
•
For 2013 the company has hedged 7,000 barrels of oil per day utilizing swaps and costless collars with a weighted average price of $99.83 and $92.50/$107.03 (floor/ceiling) respectively, and 30,000 MMBtu of natural gas per day utilizing swaps at a weighted average price of $3.89.
•
The hedges that are in place as of Oct. 31 are summarized in the following chart:

8


Commodity
Type
Index
Period
Outstanding
Forward Notional Volume
(Bbl/MMBtu)
Price
(Per Bbl/MMBtu)
Crude Oil
Collar
NYMEX
10/12 - 12/12
92,000
$80.00-$87.80
Crude Oil
Collar
NYMEX
10/12 - 12/12
92,000
$80.00-$94.50
Crude Oil
Collar
NYMEX
10/12 - 12/12
92,000
$80.00-$98.36
Crude Oil
Collar
NYMEX
10/12 - 12/12
46,000
$85.00-$102.75
Crude Oil
Collar
NYMEX
10/12 - 12/12
46,000
$85.00-$103.00
Crude Oil
Swap
NYMEX
10/12 - 12/12
46,000
$100.10
Crude Oil
Swap
NYMEX
10/12 - 12/12
46,000
$100.00
Crude Oil
Swap
NYMEX
10/12 - 12/12
92,000
$110.30
Crude Oil
Swap
NYMEX
10/12 - 12/12
92,000
$96.00
Crude Oil
Swap
NYMEX
10/12 - 12/12
92,000
$99.00
Natural Gas
Swap
NYMEX
10/12 - 12/12
874,000
$6.27
Natural Gas
Swap
NYMEX
10/12 - 12/12
460,000
$5.005
Natural Gas
Swap
NYMEX
10/12 - 12/12
230,000
$5.005
Natural Gas
Swap
NYMEX
10/12 - 12/12
230,000
$5.0125
Natural Gas
Swap
NYMEX
10/12 - 12/12
920,000
$3.05
Natural Gas
Swap
NYMEX
10/12 - 12/12
920,000
$2.805
Natural Gas
Swap
Ventura
10/12 - 12/12
920,000
$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
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$104.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$104.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$98.00
Crude Oil
Swap
NYMEX
1/13 - 12/13
182,500
$98.00
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
Basis Swap
CIG
10/12 - 12/12
690,000
$0.405
Natural Gas
Basis Swap
CIG
10/12 - 12/12
184,000
$0.41
Notes:
ž  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.
ž  For all basis swaps, index prices are below NYMEX prices and are reported as a positive amount in the price column.


9


Regulated
Electric and Natural Gas Utilities

Electric
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions, where applicable)
Operating revenues
$
63.5

 
$
61.9

 
$
174.4

 
$
169.8

Operating expenses:
 
 
 

 
 
 
 
Fuel and purchased power
17.6

 
17.4

 
51.2

 
48.8

Operation and maintenance
17.9

 
18.1

 
53.1

 
52.4

Depreciation, depletion and amortization
8.1

 
8.1

 
24.2

 
24.2

Taxes, other than income
2.6

 
2.4

 
7.9

 
7.5

 
46.2

 
46.0

 
136.4

 
132.9

Operating income
17.3

 
15.9

 
38.0

 
36.9

Earnings
$
11.0

 
$
8.3

 
$
23.0

 
$
21.7

Retail sales (million kWh)
753.8

 
718.8

 
2,189.8

 
2,128.1

Sales for resale (million kWh)
8.9

 
35.3

 
11.8

 
63.9

Average cost of fuel and purchased power per kWh
$
.022

 
$
.022

 
$
.022

 
$
.021

 
 
 
 
 
 
 
 
Natural Gas Distribution
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions)
Operating revenues
$
80.1

 
$
92.4

 
$
504.8

 
$
627.5

Operating expenses:
 
 
 
 
 
 
 
Purchased natural gas sold
38.0

 
49.3

 
300.2

 
408.8

Operation and maintenance
31.8

 
34.8

 
102.9

 
102.5

Depreciation, depletion and amortization
11.4

 
11.1

 
34.0

 
33.4

Taxes, other than income
7.0

 
7.3

 
33.2

 
35.7

 
88.2

 
102.5

 
470.3

 
580.4

Operating income (loss)
(8.1
)
 
(10.1
)
 
34.5

 
47.1

Earnings (loss)
$
(8.8
)
 
$
(11.2
)
 
$
10.3

 
$
18.2

Volumes (MMdk):
 

 
 

 
 
 
 
Sales
8.0

 
8.4

 
60.1

 
69.7

Transportation
30.0

 
28.0

 
94.7

 
87.7

Total throughput
38.0

 
36.4

 
154.8

 
157.4

Degree days (% of normal)*
 
 
 
 
 
 
 
Montana-Dakota/Great Plains
38
%
 
54
%
 
75
%
 
110
%
Cascade
91
%
 
78
%
 
98
%
 
104
%
Intermountain
51
%
 
39
%
 
92
%
 
110
%
* Degree days are a measure of the daily temperature-related demand for energy for heating.


10


The combined utility businesses reported earnings of $2.2 million in the third quarter of 2012, compared to a loss of $2.9 million for the same period in 2011. The increase in earnings reflects lower operation and maintenance expense, largely benefit-related as well as 5 percent higher electric retail sales volumes.

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

•
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 to be effective within 30 days.
•
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 completed in 2015. Advance determination of prudence for recovery of costs related to this system in electric rates charged to customers has been approved by the North Dakota Public Service Commission.
•
The company plans to construct and operate an 88-MW simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $85 million and a projected in-service date 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 $75 million in 2012 to serve the growing electric and gas customer base associated with the Bakken oil development in western North Dakota and eastern Montana.
•
The company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors with company and customer-owned pipeline facilities designed to serve existing facilities currently served by fuel oil or propane, and to serve new customers. The company is currently engaged in a 30-mile natural gas line project 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 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.

11


Pipeline and Energy Services
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions)
Operating revenues
$
48.3

 
$
69.1

 
$
141.6

 
$
215.5

Operating expenses:
 
 
 

 
 

 
 

Purchased natural gas sold
10.8

 
31.8

 
35.4

 
99.8

Operation and maintenance
19.2

 
16.6

 
34.8

*
52.8

Depreciation, depletion and amortization
7.3

 
6.4

 
20.4

 
19.3

Taxes, other than income
3.5

 
3.4

 
10.5

 
10.3

 
40.8

 
58.2

 
101.1

 
182.2

Operating income
7.5

 
10.9

 
40.5

 
33.3

Earnings
$
3.3

 
$
5.2

 
$
21.9

*
$
16.9

Transportation volumes (MMdk)
34.1

 
29.4

 
103.0

 
82.5

Natural gas gathering volumes (MMdk)
10.7

 
16.4

 
36.5

 
50.8

Customer natural gas storage balance (MMdk):
 
 
 

 
 

 
 

Beginning of period
40.4

 
31.7

 
36.0

 
58.8

Net injection (withdrawal)
8.8

 
6.8

 
13.2

 
(20.3
)
End of period
49.2

 
38.5

 
49.2

 
38.5

*  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.

This segment reported third quarter earnings of $3.3 million, compared to earnings of $5.2 million for the same period in 2011. The earnings decrease reflects lower natural gas gathering volumes and higher operation and maintenance expense, including higher payroll-related and legal costs. Partially offsetting these decreases was higher storage services revenue.

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

•
The company along with Calumet Refining, LLC, continues 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. Options to purchase land for the plant site were recently exercised. Total project costs are estimated to be approximately $280 million to $300 million with a projected in-service date in 2014.
•
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 expects to invest 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 expects average natural gas storage balances for the remainder of the year to be slightly higher than last year. The curtailment and/or divestment 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.
•
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 gas into the Northern Border Pipeline.

12


•
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.

Construction

Construction Materials and Contracting
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(Dollars in millions)
Operating revenues
$
650.0

 
$
619.1

 
$
1,241.5

 
$
1,138.2

Operating expenses:
 
 
 
 
 
 
 
Operation and maintenance
549.6

 
530.7

 
1,103.3

 
1,011.8

Depreciation, depletion and amortization
20.3

 
21.6

 
59.9

 
64.2

Taxes, other than income
11.0

 
11.1

 
29.6

 
28.6

 
580.9

 
563.4

 
1,192.8

 
1,104.6

Operating income
69.1

 
55.7

 
48.7

 
33.6

Earnings
$
41.9

 
$
33.1

 
$
24.7

 
$
16.7

Sales (000's):
 
 
 

 
 
 
 
Aggregates (tons)
9,009

 
9,196

 
17,983

 
18,502

Asphalt (tons)
3,013

 
3,462

 
4,874

 
5,469

Ready-mixed concrete (cubic yards)
1,105

 
986

 
2,410

 
2,081

Construction Services
 
 
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(In millions)
Operating revenues
$
247.2

 
$
226.2

 
$
689.4

 
$
627.6

Operating expenses:
 
 
 

 
 
 
 
Operation and maintenance
219.9

 
208.0

 
606.5

 
571.2

Depreciation, depletion and amortization
2.8

 
2.8

 
8.3

 
8.5

Taxes, other than income
7.2

 
5.8

 
22.1

 
19.0

 
229.9

 
216.6

 
636.9

 
598.7

Operating income
17.3

 
9.6

 
52.5

 
28.9

Earnings
$
9.9

 
$
5.1

 
$
30.0

 
$
15.8


The combined construction businesses reported third quarter earnings of $51.8 million, compared to earnings of $38.2 million a year ago. The earnings increase reflects higher construction margins and higher asphalt oil margins and volumes at the materials group, as well as higher construction workloads and margins and higher equipment sales and rental margins at the services group. In addition, the construction businesses on a combined basis reported lower selling, general and administrative costs.

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


13


•
The construction materials work backlog as of Sept. 30 was approximately $464 million, compared to approximately $448 million a year ago. Private work represents 17 percent of the backlog, up from 8 percent in the second quarter. Public work represents 83 percent of the backlog. The Sept. 30 backlog at construction services was approximately $370 million, compared to approximately $331 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 backlog in the Bakken area of North Dakota is approximately $50 million.
•
Projected revenues included in the company's 2012 earnings guidance are approximately $1.5 billion for construction materials and approximately $900 million for construction services.
•
The company anticipates margins in 2012 to be higher compared to 2011.
•
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 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.

Other

 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(In millions)
Operating revenues
$
2.3

 
$
2.6

 
$
7.0

 
$
7.9

Operating expenses:
 
 
 
 
 
 
 
Operation and maintenance
1.5

 
1.6

 
4.4

 
6.5

Depreciation, depletion and amortization
.5

 
.4

 
1.5

 
1.2

Taxes, other than income
—

 
.1

 
.1

 
.1

 
2.0

 
2.1

 
6.0

 
7.8

Operating income
.3

 
.5

 
1.0

 
.1

Income from continuing operations
.8

 
.9

 
1.9

 
2.0

Income (loss) from discontinued operations, net of tax
(.1
)
 
(.1
)
 
4.8

 
.1

Earnings
$
.7

 
$
.8

 
$
6.7

 
$
2.1


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 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.


14


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 oil 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 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.

15


◦
Changes in present or prospective generation.
◦
The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings.
◦
The availability of economic expansion or development opportunities.
◦
Population growth rates and demographic patterns.
◦
Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services.
◦
The cyclical nature of large construction projects at certain operations.
◦
Changes in tax rates or policies.
◦
Unanticipated project delays or changes in project costs, including related energy costs.
◦
Unanticipated changes in operating expenses or capital expenditures.
◦
Labor negotiations or disputes.
◦
Inability of the various contract counterparties to meet their contractual obligations.
◦
Changes in accounting principles and/or the application of such principles to the company.
◦
Changes in technology.
◦
Changes in legal or regulatory proceedings.
◦
The ability to effectively integrate the operations and the internal controls of acquired companies.
◦
The ability to attract and retain skilled labor and key personnel.
◦
Increases in employee and retiree benefit costs and funding requirements.

For a further discussion of these risk factors and cautionary statements, refer to Item 1A – Risk Factors in the company’s most recent Form 10-K and Form 10-Q.

16



MDU Resources Group, Inc.
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2012

 
2011

 
2012

 
2011

 
(In millions, except per share amounts)
 
(Unaudited)
Operating revenues
$
1,173.5

 
$
1,152.2

 
$
2,994.3

 
$
2,984.7

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased power
17.6

 
17.4

 
51.2

 
48.8

Purchased natural gas sold
35.2

 
50.1

 
279.1

 
396.3

Operation and maintenance
861.7

 
837.0

 
1,982.3

 
1,871.4

Depreciation, depletion and amortization
91.8

 
88.9

 
260.9

 
256.8

Taxes, other than income
41.1

 
39.4

 
132.0

 
131.6

Write-down of oil and natural gas properties
160.1

 
—

 
160.1

 
—

 
1,207.5

 
1,032.8

 
2,865.6

 
2,704.9

Operating income (loss)
(34.0
)
 
119.4

 
128.7

 
279.8

Earnings from equity method investments
2.4

 
.8

 
4.0

 
2.2

Other income
1.7

 
1.3

 
4.1

 
5.1

Interest expense
19.9

 
19.6

 
56.9

 
61.6

Income (loss) before income taxes
(49.8
)
 
101.9

 
79.9

 
225.5

Income taxes
(20.3
)
 
37.8

 
24.5

 
73.6

Income (loss) from continuing operations
(29.5
)
 
64.1

 
55.4

 
151.9

Income (loss) from discontinued operations, net of tax
(.1
)
 
(.1
)
 
4.8

 
.1

Net income (loss)
(29.6
)
 
64.0

 
60.2

 
152.0

Dividends declared on preferred stocks
.2

 
.2

 
.5

 
.5

Earnings (loss) on common stock
$
(29.8
)
 
$
63.8

 
$
59.7

 
$
151.5

 
 
 
 
 
 
 
 
Earnings (loss) per common share – basic:
 
 
 
 
 
 
 
Earnings (loss) before discontinued operations
$
(.16
)
 
$
.34

 
$
.29

 
$
.80

Discontinued operations, net of tax
—

 
—

 
.03

 
—

Earnings (loss) per common share – basic
$
(.16
)
 
$
.34

 
$
.32

 
$
.80

Earnings (loss) per common share – diluted:
 
 
 
 
 
 
 
Earnings (loss) before discontinued operations
$
(.16
)
 
$
.34

 
$
.29

 
$
.80

Discontinued operations, net of tax
—

 
—

 
.03

 
—

Earnings (loss) per common share – diluted
$
(.16
)
 
$
.34

 
$
.32

 
$
.80

Dividends declared per common share
$
.1675

 
$
.1625

 
$
.5025

 
$
.4875

Weighted average common shares outstanding – basic
188.8

 
188.8

 
188.8

 
188.8

Weighted average common shares outstanding – diluted
188.8

 
188.8

 
189.0

 
188.8


Note: Three months and nine months ended Sept. 30, 2012 results reflect the effects of a $100.9 million after tax noncash write-down of oil and natural gas properties. Nine months ended Sept. 30, 2012 results reflect the effects of a net benefit of $24.1 million ($15.0 million after tax) related to natural gas gathering operations litigation.


17




Nine Months Ended
 
September 30,
 
2012

 
2011

 
(Unaudited)
 
 
 
 
Other Financial Data
 
 
 
Book value per common share
$
14.45

 
$
14.70

Market price per common share
$
22.04

 
$
19.19

Dividend yield (indicated annual rate)
3.0
%
 
3.4
%
Price/earnings ratio*
***

 
15.1x

Market value as a percent of book value
152.5
%
 
130.5
%
Return on average common equity*
4.3
%
 
8.9
%
Total assets**
$
6.9

 
$
6.4

Total equity**
$
2.7

 
$
2.8

Total debt **
$
1.8

 
$
1.4

Capitalization ratios:


 


Total equity
61
%
 
66
%
Total debt
39

 
34

 
100
%
 
100
%
    *    Represents 12 months ended
  **    In billions
***    Not meaningful because of effects of third quarter noncash write-down of $100.9 million after tax


18