exhibit99.htm

EX-99 2 exhibit99.htm EXHIBIT 99 exhibit99.htm

MDU Resources Reports Third Quarter Earnings, Updates Earnings Guidance

Consolidated earnings of $60.8 million, or 32 cents per share, including $16.5 million after-tax charge, or 9 cents per common share.

Record seasonal natural gas storage levels at the pipeline segment.

Investment in Bakken development results in increased oil production.

Signed agreement to sell 25 percent working interest in Niobrara acreage.

BISMARCK, N.D. – Oct. 27, 2010 – MDU Resources Group, Inc. (NYSE:MDU) today reported third quarter earnings of $60.8 million, or 32 cents per common share, including a $16.5 million after-tax charge, or 9 cents per common share, related to a previously announced adverse arbitration ruling at its pipeline segment. Earnings for the third quarter of 2009 were $92.4 million, or 50 cents per common share.

“Our results are strong considering that an economic recovery is not apparent in most parts of the country,” said Terry D. Hildestad, president and CEO of MDU Resources. “Our diversified business strategy is one of our core strengths, and it is especially valuable in helping offset the market conditions that are affecting the nation’s construction industry, including our construction businesses.

“As a result, we continue to have a very solid financial position,” Hildestad said. “We have a strong balance sheet and access to significant liquidity, and will generate good cash flow this year. This has given us the ability to reward investors through the payment of a competitive dividend, in addition to opportunities to grow our company through capital investments and strategic mergers and acquisitions.

“We are updating our 2010 guidance. When excluding the third quarter arbitration charge and the potential gain from the sale of our Brazilian transmission assets expected to occur in the fourth quarter, the range is $1.10 to $1.25 per common share. The range remains the same when including these items.”

The natural gas and oil production business reported third quarter earnings of $18.7 million. Oil production increased by 24 percent in the Bakken, and average realized oil prices were up 20 percent. However, this was more than offset by lower average realized prices for natural gas, increased depreciation, depletion and amortization expense, and lower natural gas production.

Earlier this year, the natural gas and oil business acquired approximately 88,000 net acres in the emerging Niobrara oil shale play. Since that time, interest and leasehold costs in the play have increased. The company recently signed an agreement to sell a 25 percent working interest to a well-capitalized partner, which helps manage the company’s overall portfolio risk and capital requirements.

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An additional 10,000 net acres of leaseholds were recently acquired by the natural gas and oil production business in the Heart River area of the Bakken, bringing its total acreage position in the Bakken oil play to more than 67,000 net acres.

The pipeline and energy services business had earnings of $9.1 million, absent an arbitration charge. When including the charge ($16.5 million after tax), a loss of $7.4 million was reported. Seasonal storage volumes continued to be at record levels in the third quarter, but were more than offset by higher operation and maintenance expense and lower transportation and gathering volumes.

The electric and natural gas utility business reported earnings of $1.2 million, primarily on the strength of electric utility earnings of $11.3 million. The natural gas utility experienced a normal third quarter seasonal loss. Integration efforts are continuing to produce cost efficiencies for this business and customer counts continue to grow, increasing an average of 1.2 percent year-to-date.

Our construction businesses had combined earnings of $46.3 million this quarter, despite difficult economic conditions. The construction materials and contracting business earned $40.3 million, and the construction services segment had earnings of $6 million.

“Our construction businesses have done an outstanding job of lowering their cost structures, which puts us in strong position when recovery occurs,” Hildestad said. “But in the meantime, limited bidding opportunities and uncertainties with federal highway transportation funding are creating very difficult market conditions.

“Our company continues to have a strong long-term outlook. We have growth opportunities throughout our industries and expect the valuable assets that we hold will provide solid shareholder returns in the future, just as in the past.”

The company will host a webcast at 11 a.m. EDT Thursday, Oct. 28 to discuss earnings results and guidance. The event can be accessed at www.mdu.com. A webcast replay and audio replay will be available. The dial-in number for audio replay is (800) 642-1687 or (706) 645-9291 for international callers, conference ID 13471172.

MDU Resources Group, Inc., a Fortune 500 company and a member of the S&P MidCap 400 index, provides value-added natural resource products and related services that are essential to energy and transportation infrastructure, including regulated businesses, an exploration and production company and construction companies. MDU Resources includes regulated electric and natural gas utilities and regulated natural gas pipelines and energy services, natural gas and oil production, construction materials and contracting, and construction services. For more information about MDU Resources, see the company's Web site at www.mdu.com or contact the Investor Relations Department at investor@mduresources.com.

Contacts

Financial:

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

Media:

Rick Matteson, director of communications and public affairs, (701) 530-1700

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Quarterly 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 2010 (In Millions)			Earnings Third Quarter 2009 (In Millions)
Exploration and Production
Natural gas and oil production	$	18.7		$	24.4
Regulated
Pipeline and energy services		(7.4	)*		10.6
Electric and natural gas utilities		1.2			.8
Construction
Construction materials and contracting		40.3			47.5
Construction services		6.0			7.3
Other		2.0			1.8
Earnings on common stock	$	60.8	*	$	92.4
* Reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax).

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

Earnings per common share for 2010, diluted, are projected in the range of $1.10 to $1.25, excluding the third quarter $16.5 million after-tax arbitration charge and a potential gain on the sale of the company’s Brazilian transmission lines, which is expected to be completed this year. (Including the arbitration charge and the potential gain on the pending Brazilian sale, guidance for 2010 is also $1.10 to $1.25 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 percent to 10 percent.

The company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.

Estimated capital expenditures for 2010 are approximately $555 million, including the acquisition of producing natural gas properties located in the Green River Basin in southwest Wyoming. The reduction as compared to August projections is largely related to proceeds from completed and pending property sales in the natural gas and oil production and construction materials businesses.

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Exploration and Production

Natural Gas and Oil Production
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	54.9	$	67.3	$	167.7	$	218.2
Oil		52.1		42.1		157.7		102.1
		107.0		109.4		325.4		320.3
Operating expenses:
Operation and maintenance:
Lease operating costs		19.4		16.3		51.5		54.2
Gathering and transportation		5.9		6.1		17.6		18.3
Other		7.5		7.9		24.9		29.0
Depreciation, depletion and amortization		34.1		29.1		96.4		101.9
Taxes, other than income:
Production and property taxes		8.1		8.1		26.6		21.2
Other		.2		.1		.7		.6
Write-down of natural gas and oil properties		---		---		---		620.0
		75.2		67.6		217.7		845.2
Operating income (loss)		31.8		41.8		107.7		(524.9	)
Earnings (loss)	$	18.7	$	24.4	$	65.0	$	(328.2	)
Production:
Natural gas (MMcf)		12,686		13,657		37,738		43,355
Oil (MBbls)		835		807		2,427		2,320
Total Production (MMcfe)		17,696		18,502		52,298		57,277
Average realized prices (including hedges):
Natural gas (per Mcf)	$	4.33	$	4.93	$	4.44	$	5.03
Oil (per barrel)	$	62.41	$	52.13	$	65.00	$	44.00
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	3.38	$	2.34	$	3.74	$	2.82
Oil (per barrel)	$	62.12	$	55.00	$	65.21	$	45.42
Average depreciation, depletion and amortization rate, per equivalent Mcf	$	1.84	$	1.47	$	1.75	$	1.69
Production costs, including taxes, per net equivalent Mcf:
Lease operating costs	$	1.10	$	.88	$	.98	$	.95
Gathering and transportation		.33		.33		.34		.32
Production and property taxes		.46		.43		.51		.37
	$	1.89	$	1.64	$	1.83	$	1.64

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The natural gas and oil production segment reported quarterly earnings of $18.7 million, compared to $24.4 million in 2009. This decrease reflects 12 percent lower average realized natural gas prices, increased depreciation, depletion and amortization expense, higher lease operating costs, as well as decreased combined production of 4 percent. Partially offsetting these decreases was 20 percent higher average realized oil prices.

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

The company expects to spend approximately $365 million in capital expenditures in 2010, excluding property sales. This is approximately double the level of capital invested in 2009 and reflects further exploitation of existing properties, leasehold acquisitions in the Bakken and Niobrara oil shale plays and the acquisition of producing natural gas properties located in the Green River Basin. The capital expenditures forecasted reflect a shift from certain natural gas development activities to oil shale leasehold acquisitions, which will affect short-term production growth.

In 2010, the company acquired more than 50,000 net exploratory acres in the North Dakota Bakken area, bringing its total acreage position in this oil play to more than 67,000 net acres. The newly acquired acreage, the Heart River project, is located in Stark County. Plans include drilling three exploratory wells this year to evaluate this acreage targeting the Three Forks formation. Initial lease terms extend up to five years and include renewal options available to the company.

Also in 2010, the company acquired approximately 88,000 net exploratory acres in the emerging Niobrara oil play in Laramie and Goshen Counties in southeastern Wyoming. In October 2010, an agreement was signed to sell a 25 percent working interest in this acreage, reducing the company’s portfolio risk and capital requirements, bringing its acreage position to approximately 66,000 net acres. The company plans to begin drilling exploratory wells in the area in 2011. Lease terms are generally five years with most having five-year renewal options available to the company.

On a combined basis for the Heart River project and Niobrara areas, a potential of over 175 total drill sites exist assuming 640-acre spacing. Although these areas are both emerging plays, early results by other producers in these areas appear promising.

Because of reduced capital spending in 2009 and the redirecting of forecasted 2010 capital expenditures, along with delays in obtaining well completion/frac services, the company expects its 2010 combined natural gas and oil production to be approximately 6 percent below 2009 levels.

Earnings guidance reflects estimated natural gas prices for November and December as follows:

Index	Price/Thousand Cubic Feet (Mcf)
Ventura	$3.50 to $4.00
NYMEX	$3.75 to $4.25
CIG	$3.25 to $3.75

Earnings guidance reflects estimated NYMEX crude oil prices for November and December in the range of $75 to $80 per barrel.

For the last three months of 2010, the company has hedged approximately 50 percent to 55 percent of its estimated natural gas production and 40 percent to 45 percent of its estimated oil production. For 2011, the company has hedged 15 percent to 20 percent of its estimated natural gas production and 45 percent to 50 percent of its estimated oil production. For 2012, the company has hedged 5 percent to 10 percent of its estimated natural gas production and 15 percent to 20 percent of its estimated oil production. The hedges that are in place as of Oct. 27 are summarized in the following chart:

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Commodity	Type	Index	Period Outstanding	Forward Notional Volume (MMBtu/Bbl)	Price (Per MMBtu/Bbl)
Natural Gas	Swap	HSC	10/10 - 12/10	404,800	$8.08
Natural Gas	Swap	NYMEX	10/10 - 12/10	920,000	$6.18
Natural Gas	Swap	NYMEX	10/10 - 12/10	460,000	$6.40
Natural Gas	Collar	NYMEX	10/10 - 12/10	460,000	$5.63-$6.00
Natural Gas	Swap	NYMEX	10/10 - 12/10	460,000	$5.855
Natural Gas	Swap	NYMEX	10/10 - 12/10	460,000	$6.045
Natural Gas	Swap	NYMEX	10/10 - 12/10	460,000	$6.045
Natural Gas	Swap	CIG	10/10 - 12/10	920,000	$5.03
Natural Gas	Swap	HSC	10/10	62,000	$5.57
Natural Gas	Swap	NYMEX	10/10	248,000	$5.645
Natural Gas	Swap	Ventura	10/10 - 12/10	460,000	$5.95
Natural Gas	Swap	NYMEX	10/10 - 12/10	1,012,000	$5.54
Natural Gas	Collar	NYMEX	10/10 - 3/11	910,000	$5.62-$6.50
Natural Gas	Swap	HSC	1/11 - 12/11	1,350,500	$8.00
Natural Gas	Swap	NYMEX	1/11 - 12/11	4,015,000	$6.1027
Natural Gas	Swap	NYMEX	1/11 - 12/11	3,650,000	$5.4975
Natural Gas	Swap	NYMEX	1/12 - 12/12	3,477,000	$6.27
Crude Oil	Collar	NYMEX	10/10 - 12/10	92,000	$60.00-$75.00
Crude Oil	Swap	NYMEX	10/10 - 12/10	92,000	$73.20
Crude Oil	Collar	NYMEX	10/10 - 12/10	92,000	$70.00-$86.00
Crude Oil	Swap	NYMEX	10/10 - 12/10	92,000	$83.05
Crude Oil	Collar	NYMEX	1/11 - 12/11	547,500	$80.00-$94.00
Crude Oil	Collar	NYMEX	1/11 - 12/11	365,000	$80.00-$89.00
Crude Oil	Collar	NYMEX	1/11 - 12/11	182,500	$77.00-$86.45
Crude Oil	Collar	NYMEX	1/11 - 12/11	182,500	$75.00-$88.00
Crude Oil	Swap	NYMEX	1/11 - 12/11	365,000	$81.35
Crude Oil	Swap	NYMEX	1/11 - 12/11	182,500	$85.85
Crude Oil	Collar	NYMEX	1/12 - 12/12	366,000	$80.00-$87.80
Crude Oil	Collar	NYMEX	1/12 - 12/12	366,000	$80.00-$94.50
Natural Gas	Basis Swap	Ventura	10/10 - 12/10	920,000	$0.25
Natural Gas	Basis Swap	Ventura	10/10 - 12/10	230,000	$0.245
Natural Gas	Basis Swap	Ventura	10/10 - 12/10	1,150,000	$0.25
Natural Gas	Basis Swap	Ventura	10/10 - 12/10	460,000	$0.225
Natural Gas	Basis Swap	Ventura	10/10 - 12/10	230,000	$0.23
Natural Gas	Basis Swap	Ventura	10/10 - 12/10	690,000	$0.23
Natural Gas	Basis Swap	CIG	10/10 - 12/10	1,012,000	$0.385
Natural Gas	Basis Swap	Ventura	1/11 - 3/11	450,000	$0.135
Natural Gas	Basis Swap	CIG	1/11 - 12/11	4,015,000	$0.395
Natural Gas	Basis Swap	Ventura	1/11 - 12/11	3,650,000	$0.15
Natural Gas	Basis Swap	CIG	1/12 - 12/12	2,745,000	$0.405
Natural Gas	Basis Swap	CIG	1/12 - 12/12	732,000	$0.41
Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column.

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Regulated

Pipeline and Energy Services

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010			2009		2010			2009
	(Dollars in millions)
Operating revenues	$	81.2		$	68.7	$	250.3		$	221.8
Operating expenses:
Purchased natural gas sold		36.8			25.7		119.5			100.0
Operation and maintenance		44.2	*		14.0		77.2	*		42.8
Depreciation, depletion and amortization		6.5			6.6		19.4			18.8
Taxes, other than income		3.2			3.0		9.5			8.9
		90.7			49.3		225.6			170.5
Operating income (loss)		(9.5	)		19.4		24.7			51.3
Earnings (loss)	$	(7.4	)	$	10.6	$	10.9		$	27.9
Transportation volumes (MMdk)		33.6			41.2		108.4			122.2
Gathering volumes (MMdk)		19.3			22.7		57.7			71.3
Customer natural gas storage balance (MMdk):
Beginning balance**		64.2			41.6		61.5			30.6
Net injection		9.6			19.4		12.3			30.4
Ending balance		73.8			61.0		73.8			61.0
* Reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax). ** As of the beginning of the applicable period.

The pipeline and energy services segment reported a third quarter loss of $7.4 million, compared to earnings of $10.6 million in the third quarter of 2009. This decrease reflects higher operation and maintenance expense, largely resulting from a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax), lower volumes transported to storage, as well as lower gathering volumes. Partially offsetting these items was higher storage services revenue.

The company was notified on Oct. 15 of the Colorado arbitration decision, which involves a disagreement regarding the terms of operation and pressure of a gathering system owned by Bitter Creek Pipelines, LLC, a non-regulated subsidiary. The company is assessing all legal remedies available to challenge the outcome of the award.

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

The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken Shale of North Dakota and eastern Montana. Ongoing energy development is expected to have many direct and indirect benefits to its business.

The company continues to pursue the expansion of its existing natural gas pipeline capacity by 30,000 Mcf per day in the Bakken production area in northwestern North Dakota. This expansion project is targeted for late 2011.

The company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. The company continues to see strong interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by

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125,000 Mcf per day and related transportation capacity. The company has received commitment on approximately 30 percent of the total potential project and is moving forward on that phase with a projected in-service date of November 2011, subject to regulatory approval.

Electric and Natural Gas Utilities

Electric
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Dollars in millions, where applicable)
Operating revenues	$	60.0		$	51.9		$	155.3		$	147.7
Operating expenses:
Fuel and purchased power		15.3			15.2			45.3			49.1
Operation and maintenance		15.7			13.8			47.0			45.3
Depreciation, depletion and amortization		7.6			6.1			19.5			18.2
Taxes, other than income		2.2			2.2			7.0			7.0
		40.8			37.3			118.8			119.6
Operating income		19.2			14.6			36.5			28.1
Earnings	$	11.3		$	10.1		$	22.1		$	18.5
Retail sales (million kWh)		692.0			655.0			2,057.0			1,975.2
Sales for resale (million kWh)		13.8			11.7			51.1			44.1
Average cost of fuel and purchased power per kWh	$	.021		$	.022		$	.021		$	.023

Natural Gas Distribution
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
		2010			2009			2010			2009
	(Dollars in millions)
Operating revenues	$	94.3		$	97.4		$	603.5		$	744.8
Operating expenses:
Purchased natural gas sold		50.1			55.6			394.3			529.0
Operation and maintenance		35.7			31.6			102.8			105.3
Depreciation, depletion and amortization		10.8			10.8			32.1			32.1
Taxes, other than income		7.5			7.3			34.5			41.5
		104.1			105.3			563.7			707.9
Operating income (loss)		(9.8	)		(7.9	)		39.8			36.9
Earnings (loss)	$	(10.1	)	$	(9.3	)	$	13.4		$	9.8
Volumes (MMdk):
Sales		7.9			7.5			61.6			65.2
Transportation		35.4			38.2			98.7			95.6
Total throughput		43.3			45.7			160.3			160.8
Degree days (% of normal)*
Montana-Dakota		69	%		30	%		97	%		103	%
Cascade		109	%		80	%		96	%		105	%
Intermountain		105	%		103	%		103	%		104	%
* Degree days are a measure of the daily temperature-related demand for energy for heating.

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The combined utility business reported earnings of $1.2 million, compared to earnings of $800,000 for the third quarter of 2009. The increase in earnings reflects higher electric retail sales margins and volumes, partially offset by higher operation and maintenance expense, increased depreciation, depletion and amortization expense and decreased natural gas retail sales margins.

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

·	The company continues to realize efficiencies and enhanced service levels through its efforts to standardize operations, share services and consolidate back-office functions among its four utility companies.

In April, the company filed an application with the North Dakota Public Service Commission for an electric rate increase of $15.4 million annually, or 14 percent above current rates. The requested increase included the investment in infrastructure upgrades, recovery of the investment in renewable generation and the costs associated with the Big Stone II plant. A settlement agreement has been approved providing for separate recovery of the costs associated with Big Stone II of $9.6 million over three years. A partial settlement agreement has also been reached related to cost of capital and capital structure. The settlements effectively reduce the requested rate increase to $11.5 million annually, a 10 percent increase. An interim increase of $7.6 million annually was effective June 18. A hearing on the case is scheduled for Nov. 8.

In August, the company filed an application with the Montana Public Service Commission for an electric rate increase of $5.5 million annually, or 13 percent above current rates. The requested increase includes the investment in infrastructure upgrades, recovery of the investment in renewable generation, the costs associated with the Big Stone II plant and the significant loss of wholesale sales margins. The MTPSC has up to nine months to render a decision on this request. A hearing on the case is scheduled for Feb. 28, 2011. Montana-Dakota requested an interim increase of $3.1 million or approximately 7.4 percent, which is pending before the MTPSC.

·	The company is developing a landfill methane gas recovery project in Billings, Montana to supplement the company’s gas supply portfolio. The project is expected to begin production in December, and upon total phase-in to recover up to 2,500 dekatherms per day.

·	The company is analyzing potential projects for accommodating load growth and replacing purchased power contracts with company-owned generation. The company is reviewing the construction of natural gas-fired combustion and wind generation.

The company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major metropolitan areas. The company has signed a contract to develop a 30-mile high-voltage power line in southeast North Dakota to move power to the electric grid from a proposed 150-megawatt wind farm being built by enXco for Xcel Energy. The project will total approximately $20 million and will include substation upgrades. Pending regulatory approval, construction is expected to begin in 2011. Customers will not bear any of the costs associated with the project as costs will be recovered through an approved interconnect tariff.

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Construction

Construction Materials and Contracting
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(Dollars in millions)
Operating revenues	$	612.7	$	622.0	$	1,124.1	$	1,194.9
Operating expenses:
Operation and maintenance		513.4		506.6		976.4		1,004.6
Depreciation, depletion and amortization		22.5		23.4		67.2		71.2
Taxes, other than income		10.1		11.5		26.6		28.8
		546.0		541.5		1,070.2		1,104.6
Operating income		66.7		80.5		53.9		90.3
Earnings	$	40.3	$	47.5	$	25.8	$	47.8
Sales (000's):
Aggregates (tons)		8,741		9,345		17,965		19,016
Asphalt (tons)		3,343		3,443		5,076		5,161
Ready-mixed concrete (cubic yards)		919		1,021		2,137		2,322

The construction materials and contracting segment reported third quarter earnings of $40.3 million, compared to $47.5 million for the same period in 2009. The decrease in earnings largely reflects lower liquid asphalt oil margins, as well as lower asphalt and ready-mixed concrete margins and volumes, partially offset by lower selling, general and administrative expense.

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

Work backlog as of Sept. 30 was approximately $464 million, with 94 percent of construction backlog being public work and private representing 6 percent. In the company’s peak earnings year of 2006, private backlog represented 40 percent of construction backlog. Total backlog at Sept. 30, 2009 was $494 million.

Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and an L.A. harbor deepening project.

Federal transportation stimulus of $7.9 billion was directed to states where the company operates. Of that amount, 52 percent was spent as of early October, with the majority of the remaining $3.8 billion to be spent during the remainder of 2010 and 2011.

The company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets.

The company has a strong emphasis on operational efficiencies and cost reduction. SG&A expenses are down 34 percent for the trailing 12 months through Sept. 30, compared to the annual expenses in 2006, the peak earnings year for this segment.

As a result of the economic downturn, the company expects overall volumes and margins to be lower in 2010 compared to 2009, at which time liquid asphalt earnings were at record levels.

As the country’s 6th largest sand and gravel producer, the company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.

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Construction Services
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In millions)
Operating revenues	$	210.5	$	186.4	$	551.8	$	651.9
Operating expenses:
Operation and maintenance		191.1		166.1		506.1		582.5
Depreciation, depletion and amortization		2.9		3.2		9.2		10.0
Taxes, other than income		5.8		5.2		18.4		21.1
		199.8		174.5		533.7		613.6
Operating income		10.7		11.9		18.1		38.3
Earnings	$	6.0	$	7.3	$	9.0	$	22.9

This segment had quarterly earnings of $6.0 million, compared to $7.3 million for the third quarter of 2009. This decrease reflects lower construction workloads and margins in the Southwest region, partially offset by higher construction workloads and margins in the Western and Mountain regions. Lower general and administrative expenses, including lower payroll-related costs, also partially offset the earnings decrease.

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

Work backlog as of Sept. 30 was approximately $317 million, $53 million higher than the Sept. 30, 2009 backlog of $264 million. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, industrial and institutional projects.

The company anticipates margins in 2010 to be lower than 2009 levels.

The company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction and military installation services. In late 2009, the company was awarded the engineering, procurement and construction contract to build the 214-mile Montana Alberta Tie Line between Lethbridge, Alberta and Great Falls, Montana. In late June, the company received a notice to proceed with construction on the project.

The company continues to focus on costs and efficiencies to enhance margins. SG&A expenses are down 30 percent for the trailing 12 months through Sept. 30, compared to the annual expenses in 2008, the peak earnings year for this segment.

With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure.

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Other

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
	(In millions)
Operating revenues	$	2.3		$	2.7	$	6.8		$	8.1
Operating expenses:
Operation and maintenance		1.9			2.3		5.6			7.5
Depreciation, depletion and amortization		.4			.3		1.2			1.0
Taxes, other than income		.1			.1		.1			.2
		2.4			2.7		6.9			8.7
Operating income (loss)		(.1	)		---		(.1	)		(.6	)
Earnings	$	2.0		$	1.8	$	5.0		$	4.9

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 and 2010 earnings guidance that reflect an adjustment to exclude a $16.5 million after-tax charge related to an adverse arbitration ruling and, with respect to the 2010 earnings guidance, also reflects an adjustment to exclude a potential gain on the expected sale of its Brazilian transmission lines in the fourth quarter. The company believes that these non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. Also, the company’s management uses these non-GAAP financial measures as indicators for planning and forecasting future periods. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

Risk Factors and Cautionary Statements that May Affect Future Results

The information in this release includes certain forward-looking statements, including earnings per share guidance and statements by the president and chief executive officer of MDU Resources, within the meaning of Section 21E of the Securities Exchange Act of 1934. Although the company believes that its expectations are based on reasonable assumptions, actual results may differ materially. Following are important factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements.

The company’s natural gas and oil production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, which are subject to various external influences that cannot be controlled.

The regulatory approval, permitting, construction, startup and operation of power generation facilities may involve unanticipated changes or delays that could negatively impact the company’s business and its results of operations and cash flows.

Economic volatility affects the company’s operations, as well as the demand for its products and services and the value of its investments and investment returns and, as a result, may have a negative impact on the company’s future revenues and cash flows.

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The company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the company’s control. If the company is unable to obtain economic financing in the future, the company’s ability to execute its business plans, make capital expenditures or pursue acquisitions that the company may otherwise rely on for future growth could be impaired. As a result, the market value of the company’s common stock may be adversely affected. If the company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders.

The company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the company’s customers and counterparties.

The backlogs at the company’s construction services and construction materials and contracting businesses are subject to delay or cancellation and may not be realized.

Actual quantities of recoverable natural gas and oil reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts.

Some of the company’s operations are subject to extensive environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the company to environmental liabilities.

The company’s electric generation operations could be adversely impacted by global climate change initiatives to reduce greenhouse gas emissions.

One of the company’s subsidiaries is and has been subject to numerous litigation and administrative proceedings in connection with its coalbed natural gas development. These proceedings have caused delays in coalbed natural gas drilling activity and resulted in more restrictive discharge limitations. There is the possibility that the company will be the subject of similar future proceedings. The ultimate outcome of the actions could have a material negative effect on existing coalbed natural gas operations and/or the future development of its coalbed natural gas properties.

The company is subject to extensive government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party’s ability to acquire the company.

The value of the company’s investments in foreign operations may diminish due to political, regulatory and economic conditions and changes in currency exchange rates in countries where the company does business.

Weather conditions can adversely affect the company’s operations and revenues and cash flows.

Competition is increasing in all of the company’s businesses.

The company could be subject to limitations on its ability to pay dividends.

An increase in costs related to obligations under multi-employer pension plans could have a material negative effect on the company’s results of operations and cash flows.

Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include:

Acquisition, disposal and impairments of assets or facilities.

Changes in operation, performance and construction of plant facilities or other assets.

Changes in present or prospective generation.

The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings.

The availability of economic expansion or development opportunities.

Population growth rates and demographic patterns.

Market demand for, and/or available supplies of, energy- and construction-related products and services.

The cyclical nature of large construction projects at certain operations.

Changes in tax rates or policies.

Unanticipated project delays or changes in project costs, including related energy costs.

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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.

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MDU Resources Group, Inc.
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In millions, except per share amounts) (Unaudited)
Operating revenues	$	1,125.9	$	1,107.9	$	2,867.1	$	3,160.0
Operating expenses:
Fuel and purchased power		15.3		15.2		45.3		49.1
Purchased natural gas sold		51.2		57.6		382.4		520.5
Operation and maintenance		828.4		757.8		1,790.4		1,868.5
Depreciation, depletion and amortization		84.8		79.5		245.0		253.2
Taxes, other than income		37.2		37.5		123.4		129.3
Write-down of natural gas and oil properties		---		---		---		620.0
		1,016.9		947.6		2,586.5		3,440.6
Operating income (loss)		109.0		160.3		280.6		(280.6	)
Earnings from equity method investments		2.5		2.3		7.0		6.2
Other income		1.7		2.9		6.9		7.1
Interest expense		20.9		20.9		62.0		62.7
Income (loss) before income taxes		92.3		144.6		232.5		(330.0	)
Income taxes		31.3		52.0		80.8		(134.1	)
Net income (loss)		61.0		92.6		151.7		(195.9	)
Dividends on preferred stocks		.2		.2		.5		.5
Earnings (loss) on common stock	$	60.8	$	92.4	$	151.2	$	(196.4	)
Earnings (loss) per common share – basic	$	.32	$	.50	$	.80	$	(1.07	)
Earnings (loss) per common share – diluted	$	.32	$	.50	$	.80	$	(1.07	)
Dividends per common share	$	.1575	$	.1550	$	.4725	$	.4650
Weighted average common shares outstanding – basic		188.2		185.2		188.1		184.3
Weighted average common shares outstanding – diluted		188.3		185.4		188.3		184.3

Note: Three months and nine months ended September 30, 2010 results reflect the effects of a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax, or $.09 per common share). Nine months ended September 30, 2009 results reflect the effects of a $384.4 million after-tax, or $2.09 per common share, noncash charge relating to the write-down of natural gas and oil properties.

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	Nine Months Ended September 30,
	2010			2009
	(Unaudited)

Other Financial Data
Book value per common share	$	14.07		$	13.37
Market price per common share	$	19.95		$	20.85
Dividend yield (indicated annual rate)		3.2	%		3.0	%
Price/earnings ratio*		16.8	x		N/A
Market value as a percent of book value		141.8	%		155.9	%
Return on average common equity*		8.6	%		(8.1	)%
Total assets**	$	6.2		$	5.9
Total equity**	$	2.7		$	2.5
Total debt **	$	1.5		$	1.5
Capitalization ratios:
Total equity		64	%		63	%
Total debt		36			37
		100	%		100	%

* Represents 12 months ended

** In billions

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