MDU Resources Reports 2010 Results, Initiates Guidance for 2011

• Consolidated 2010 earnings of $240.0 million, or $1.27 per share.
• Consolidated Fourth Quarter earnings increased from a year ago.
• Strong balance sheet with equity of 64% of total capital.
• Significant cash generated by operations and successful property sales.
• Initial earnings guidance for 2011 of $1.05 to $1.30 per common share.

BISMARCK, N.D.--(BUSINESS WIRE)--MDU Resources Group, Inc. (NYSE:MDU) today reported 2010 consolidated earnings of $240.0 million, or $1.27 per share. This compares to a 2009 loss of $124.0 million or 67 cents per share. Excluding a third quarter arbitration charge at the pipeline segment and a fourth quarter gain on the sale of the company’s Brazilian transmission lines, 2010 earnings were $242.7 million, or $1.29 per share. Excluding a first quarter 2009 noncash charge at the natural gas and oil production segment, 2009 earnings were $260.4 million, or $1.40 per share.

In the fourth quarter 2010 the company had consolidated earnings of $88.8 million, or 47 cents per share compared to $72.5 million or 38 cents per share in the fourth quarter of 2009. Excluding the gain on the sale of the company’s Brazilian transmission lines, earnings for the fourth quarter 2010 were $75.0 million, or 40 cents per share.

“I am pleased with the performance of our businesses this year despite lower realized natural gas prices and a challenging economic environment,” said Terry D. Hildestad, president and chief executive officer of MDU Resources. “These results and our solid financial condition once again demonstrate the value of our diversified business strategy. We have a strong balance sheet and generated significant cash from operations, as well as from the successful sale of our Brazilian transmission assets, and the recently announced Niobrara transaction where we de-risked our investment while maintaining significant operating interest in the acreage.”

Hildestad pointed out that MDU Resources’ investments in the North Dakota Bakken, which is one of the most active oil development areas in the U.S., have been successful. This helped earnings at the company’s exploration and production business remain strong despite a 16 percent decline in average realized natural gas prices. Oil production increased 5 percent in 2010 reflecting the group’s effort to further balance its production mix to benefit from favorable oil prices. A growing portion of the business’ 2011 capital budget will be focused on increasing oil production.

“Our plans include adding an additional drilling rig in the second quarter to accelerate our Bakken drilling activities,” Hildestad said. “We will also begin drilling test wells on our approximate 65,000 net acres in the emerging Niobrara play.”

The pipeline and energy services business also is well positioned to benefit from the Bakken activity with an extensive natural gas transmission pipeline system in the Bakken, and plans to expand its capacity during 2011. The group reported record natural gas storage levels during the third quarter at its storage fields, and is moving forward this year with the first phase of a storage expansion to add firm deliverability from its Baker storage field.

The utility business increased year-over-year earnings. This group operates in growing service territories with a customer base that now approximates 964,000 customers. The utility also added 55 megawatts of rate-based generation in 2010, including 30 MW of renewable wind energy, to maintain a reliable supply of electricity for customers. Looking forward, this business is pursuing opportunities to invest in the expected regional transmission build out and additional generation.

“The economy continues to affect volumes and margins for our construction businesses,” Hildestad added. “These are good solid fundamental businesses for the long term that are weathering a very challenging economic cycle. The leaner cost structure of these businesses positions us well as bidding opportunities increase and the potential for large multi-year projects are presented.

“For 2011, we are providing initial earnings guidance in the range of $1.05 to $1.30 per common share. Our guidance factors in the uncertainties presented by continued low private construction spending and funding for public works projects, as well as continued low natural gas prices. We are excited about the potential of our exploratory drilling program and the organic growth opportunities at our regulated operations. In addition, we continue to pursue acquisition opportunities in each line of business.”

The company will host a webcast at 11 a.m. EST Feb. 3 to discuss earnings results and initial guidance for 2011. The event can be accessed at www.mdu.com. A webcast replay and audio replay will be available. The dial-in number for audio replay is [phone] or [phone] for international callers, conference ID 34480118.

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

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.

	2010 Earnings			2009 Earnings
Business Line	(In Millions)			(In Millions)
Exploration and Production
Natural gas and oil production	$	85.6		$	87.7
Regulated
Pipeline and energy services	23.2		*		37.8
Electric and natural gas utilities		65.9			54.9
Construction
Construction materials and contracting		29.6			47.1
Construction services		18.0			25.6
Other	21.0		**		7.3
Earnings before discontinued operations and noncash charge		243.3			260.4
Loss from discontinued operations, net of tax		(3.3	)		---
Effects of noncash charge		---			(384.4	)
Earnings (loss) on common stock	$	240.0		$	(124.0	)

* Reflects a natural gas gathering arbitration charge of $16.5 million after tax.
** Reflects a gain on the sale of the Brazilian transmission lines of $13.8 million after tax.

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

• Earnings per common share for 2011, diluted, are projected in the range of $1.05 to $1.30. The company expects the approximate percentage of 2011 earnings per common share by quarter to be:
  • First quarter – 15 percent
  • Second quarter – 20 percent
  • Third quarter – 35 percent
  • Fourth quarter – 30 percent
• Although near term market conditions are uncertain, the company’s long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.
• The company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.

• Capital expenditures for 2010 and estimated capital expenditures for 2011 are noted in the following table. The company expects the 2011 estimated capital expenditures to be funded in its entirety with cash flow generated from operations.

	Capital Expenditures		Capital Expenditures
	2011 Estimated*		2010 Actual
Business Line	(In Millions)		(In Millions)
Exploration and Production
Natural gas and oil production	$ 306		$ 356	**
Regulated
Pipeline and energy services	41		14
Electric	76		86
Natural gas distribution	80		75
Construction
Construction materials and contracting	39		26
Construction services	10		15
Other	17		2
Net proceeds and other	(8	)	(79	)
Total Capital Expenditures	$ 561		$ 495

* Capital expenditures relative to potential acquisitions of businesses would be incremental to these estimates.
** Includes approximately $100 million for the acquisition of the Green River Basin properties.

Exploration and Production
Natural Gas and Oil Production
	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2010		2009		2010		2009
	(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	51.9	$	74.0	$	219.6	$	292.3
Oil		57.0		45.3		214.8		147.4
		108.9		119.3		434.4		439.7
Operating expenses:
Operation and maintenance:
Lease operating costs		16.9		15.9		68.5		70.1
Gathering and transportation		5.9		5.7		23.5		24.0
Other		7.6		10.2		32.5		39.2
Depreciation, depletion and amortization		34.1		27.9		130.5		129.9
Taxes, other than income:
Production and property taxes		8.9		7.9		35.5		29.1
Other		.1		.2		.7		.8
Write-down of natural gas and oil properties		---		---		---		620.0
		73.5		67.8		291.2		913.1
Operating income (loss)		35.4		51.5		143.2		(473.4	)
Earnings (loss)	$	20.7	$	31.4	$	85.6	$	(296.7	)
Production:
Natural gas (MMcf)		12,653		13,277		50,391		56,632
Oil (MBbls)		835		791		3,262		3,111
Total Production (MMcfe)		17,665		18,022		69,963		75,299
Average realized prices (including hedges):
Natural gas (per Mcf)	$	4.10	$	5.57	$	4.36	$	5.16
Oil (per barrel)	$	68.30	$	57.30	$	65.85	$	47.38
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	3.07	$	3.55	$	3.57	$	2.99
Oil (per barrel)	$	71.09	$	62.52	$	66.71	$	49.76
Average depreciation, depletion and
amortization rate, per equivalent Mcf	$	1.84	$	1.47	$	1.77	$	1.64
Production costs, including taxes, per
equivalent Mcf:
Lease operating costs	$	.96	$	.88	$	.98	$	.93
Gathering and transportation		.33		.31		.34		.32
Production and property taxes		.50		.44		.51		.39
	$	1.79	$	1.63	$	1.83	$	1.64
	2010				2009
	Natural Gas		Oil		Natural Gas		Oil
	(MMcf/MBbls)
Production by region:
Rocky Mountain		39,160		2,365		41,635		2,182
Mid-Continent/Gulf States*		11,231		897		14,997		929
Total Production		50,391		3,262		56,632		3,111
* Includes Offshore Gulf of Mexico.

Earnings at this segment were $85.6 million for 2010, compared to $87.7 million for 2009, which excludes the effect of a $384.4 million after-tax noncash charge. This decrease reflects 16 percent lower average realized natural gas prices, decreased natural gas production of 11 percent, as well as higher production taxes. These decreases were partially offset by 39 percent higher average realized oil prices, increased oil production of 5 percent and lower general and administrative costs.

Fourth quarter earnings were $20.7 million, compared to 2009 fourth quarter earnings of $31.4 million. This decrease reflects 26 percent lower average realized natural gas prices and increased depreciation, depletion and amortization expense, partially offset by 19 percent higher average realized oil prices.

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

• The company expects to spend approximately $306 million in capital expenditures in 2011. The company continues its focus on returns by allocating a growing portion of its capital investment into the production of oil in the current commodity price environment. The company’s capital program reflects further exploitation of existing properties, acquisition of additional leasehold acreage, and exploratory drilling. The 2011 planned capital expenditure total does not include potential acquisitions of producing properties.
• For 2011, the company expects a 5 percent to 10 percent increase in oil production offset by a 4 percent to 8 percent decrease in natural gas production. If natural gas prices recover, the company believes it is positioned to spend additional capital on drilling its low cost natural gas properties.
• Bakken – Mountrail County, North Dakota –
  • The company owns approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations with average production of approximately 3,700 net barrels per day. The drilling of 13 operated and participation in various non-operated wells is planned for 2011 with approximately $52 million of capital expenditures. The company plans to drill 12 wells annually for the two-year period 2012 through 2013.
  • Over 50 future wells sites have been identified, 20 middle Bakken infill locations and the remainder Three Forks locations. Estimated gross ultimate recovery per well for the middle Bakken wells is 250,000 barrels to 400,000 barrels.
• Bakken - Stark County, North Dakota –
  • The company holds approximately 50,000 net exploratory leasehold acres, targeting the Three Forks formation. The first test well was recently completed, the Kostelecky 31-6H, with an initial 24-hour production rate of 1,257 barrels of oil and 519 Mcf of gas, or 1,343 barrels of oil equivalents. Its second test well, the Oukrop 34-34H, was also recently completed. While it has not been production tested, initial flow back of fluids is less than expected. A third test well, Wock 14-11H, is drilled and waiting on completion. The company anticipates drilling 6 additional operated wells on this acreage and participating in various non-operated wells in Stark County in 2011 with capital of approximately $37 million.
  • Based on well results, the company plans to drill 12 or more wells annually beginning in 2012.
  • Based on 640-acre spacing, the acreage holds over 75 potential drill sites. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 barrels of oil equivalents. Based on initial well results and results by other producers, the play appears promising.
• Bakken –
  • In the second quarter, the company plans to add an additional drilling rig in the Bakken.
• Niobrara – southeastern Wyoming –
  • The company holds approximately 65,000 net exploratory leasehold acres in this emerging oil play. The company is completing seismic evaluation work on this acreage and expects to begin drilling 2 exploratory wells in 2011.
  • If successful, the company plans to initiate a drilling program of approximately 12 wells annually starting in 2012.
  • The company also expects to participate in various non-operated wells in the Niobrara.
  • The company has more than 100 future locations on this acreage based on 640-acre spacing. Although this is an emerging exploratory play, early results by certain other producers appear promising.
• Texas –
  • Based on low natural gas prices, the company is targeting areas that have the potential for higher liquids content. The company has approximately $48 million of capital targeted in 2011.
• Other Opportunities –
  • The company holds approximately 80,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana. Plans include drilling a test well in 2011.
  • The company continues to pursue acquisitions of additional leaseholds. Approximately $50 million of capital has been allocated to leasehold acquisitions in 2011, focusing on expansion of existing positions and new opportunities.
• Reserve information –
  • The company’s combined proved natural gas and oil reserves as of Dec. 31 were 646 Bcfe, compared to 654 Bcfe at Dec. 31, 2009. The change reflects approximately 57 Bcfe of extensions and discoveries, 61 Bcfe of purchases, 70 Bcfe of production and 56 Bcfe of negative reserve revisions, which include 16 Bcfe of proved undeveloped reserves that were removed as the reserves will not be developed within the required five-year period. The Dec. 31 proved reserve figure does not yet include reserves for the company’s acreage in the Bakken - Stark County or Niobrara areas because of the exploratory nature of these plays.
• Earnings guidance reflects estimated natural gas and oil prices for February through December as follows:

Natural Gas Index
NYMEX	$4.25 to $4.75 per Mcf
Ventura	$4.00 to $4.50 per Mcf
CIG	$3.75 to $4.25 per Mcf
Crude Oil Index
NYMEX	$85.00 to $90.00 per barrel

• For 2011, the company has hedged approximately 45 percent to 50 percent of its estimated natural gas production and 60 percent to 65 percent of its estimated oil production. For 2012, the company has hedged 15 percent to 20 percent of its estimated natural gas production and 35 percent to 40 percent of its estimated oil production. The hedges that are in place as of Feb. 2 are summarized in the following chart:

				Forward
				Notional
			Period	Volume	Price
Commodity	Type	Index	Outstanding	(MMBtu/Bbl)	(Per MMBtu/Bbl)
Natural Gas	Collar	NYMEX	1/11 - 3/11	450,000	$5.62-$6.50
Natural Gas	Swap	HSC	1/11 - 12/11	1,350,500	$8.00
Natural Gas	Swap	NYMEX	1/11 - 12/11	4,015,000	$6.1027
Natural Gas	Swap	NYMEX	1/11 - 12/11	3,650,000	$5.4975
Natural Gas	Swap	NYMEX	1/11 - 12/11	3,650,000	$4.58
Natural Gas	Swap	NYMEX	2/11 - 12/11	3,340,000	$4.70
Natural Gas	Swap	NYMEX	2/11 - 12/11	3,340,000	$4.75
Natural Gas	Swap	NYMEX	4/11 - 10/11	2,140,000	$4.775
Natural Gas	Swap	NYMEX	1/12 - 12/12	3,477,000	$6.27
Natural Gas	Swap	NYMEX	1/12 - 12/12	1,830,000	$5.005
Natural Gas	Swap	NYMEX	1/12 - 12/12	915,000	$5.005
Natural Gas	Swap	NYMEX	1/12 - 12/12	915,000	$5.0125
Crude Oil	Collar	NYMEX	1/11 - 12/11	547,500	$80.00-$94.00
Crude Oil	Collar	NYMEX	1/11 - 12/11	365,000	$80.00-$89.00
Crude Oil	Collar	NYMEX	1/11 - 12/11	182,500	$77.00-$86.45
Crude Oil	Collar	NYMEX	1/11 - 12/11	182,500	$75.00-$88.00
Crude Oil	Swap	NYMEX	1/11 - 12/11	365,000	$81.35
Crude Oil	Swap	NYMEX	1/11 - 12/11	182,500	$85.85
Crude Oil	Put Option	NYMEX	1/11 - 12/11	365,000	$80.00*
Crude Oil	Collar	NYMEX	1/12 - 12/12	366,000	$80.00-$87.80
Crude Oil	Collar	NYMEX	1/12 - 12/12	366,000	$80.00-$94.50
Crude Oil	Collar	NYMEX	1/12 - 12/12	366,000	$80.00-$98.36
Crude Oil	Collar	NYMEX	1/12 - 12/12	183,000	$85.00-$102.75
Crude Oil	Collar	NYMEX	1/12 - 12/12	183,000	$85.00-$103.00
Crude Oil	Swap	NYMEX	1/12 - 12/12	183,000	$100.10
Crude Oil	Swap	NYMEX	1/12 - 12/12	183,000	$100.00
Natural Gas	Basis Swap	Ventura	1/11 - 3/11	450,000	$0.135
Natural Gas	Basis Swap	CIG	1/11 - 12/11	4,015,000	$0.395
Natural Gas	Basis Swap	Ventura	1/11 - 12/11	3,650,000	$0.15
Natural Gas	Basis Swap	Ventura	2/11 - 12/11	1,670,000	$0.15
Natural Gas	Basis Swap	Ventura	2/11 - 12/11	835,000	$0.16
Natural Gas	Basis Swap	Ventura	2/11 - 12/11	3,340,000	$0.16
Natural Gas	Basis Swap	Ventura	2/11 - 12/11	4,175,000	$0.155
Natural Gas	Basis Swap	CIG	1/12 - 12/12	2,745,000	$0.405
Natural Gas	Basis Swap	CIG	1/12 - 12/12	732,000	$0.41
* Deferred premium of $4.00.

Notes: Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column.

Regulated
Pipeline and Energy Services
	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2010			2009		2010			2009
	(Dollars in millions)
Operating revenues	$	79.5		$	86.1	$	329.8		$	307.8
Operating expenses:
Purchased natural gas sold		34.3			38.8		153.9			138.8
Operation and maintenance		13.4			20.3	90.6*				63.1
Depreciation, depletion and amortization		6.6			6.8		26.0			25.5
Taxes, other than income		3.6			2.1		13.0			11.0
		57.9			68.0		283.5			238.4
Operating income		21.6			18.1		46.3			69.4
Earnings	$	12.3		$	10.0	$	23.2		$	37.8
Transportation volumes (MMdk)		32.1			41.1		140.5			163.3
Gathering volumes (MMdk)		19.5			21.3		77.2			92.6
Customer natural gas storage balance (MMdk):
Beginning of period		73.8			61.0		61.5			30.6
Net injection (withdrawal)		(15.0	)		.5		(2.7	)		30.9
End of period		58.8			61.5		58.8			61.5
* Reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax).

Earnings at the pipeline and energy services segment were $23.2 million, compared to earnings of $37.8 million in 2009. The decrease reflects higher operation and maintenance expense, lower gathering volumes, as well as lower volumes transported to storage, partially offset by higher storage services revenue. Higher operation and maintenance expense is primarily the result of a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax), partially offset by lower costs related to natural gas storage litigation, largely because of an insurance recovery. The natural gas storage litigation was settled in July 2009.

Fourth quarter earnings for 2010 were $12.3 million, compared to $10.0 million for the comparable prior period. The increase reflects lower operation and maintenance expense, primarily the result of lower costs related to natural gas storage litigation, largely because of an insurance recovery, partially offset by decreased volumes transported to storage.

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

• The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken of North Dakota and eastern Montana. The company owns an extensive natural gas pipeline system in the Bakken area. Ongoing energy development is expected to have many direct and indirect benefits to this business.
• The company continues to pursue the expansion of its existing natural gas pipeline in the Bakken production area in northwestern North Dakota. It is currently soliciting customer interest in a 27 MMcf per day expansion of capacity out of the area targeted for late 2011.
• Final agreements have been executed to construct approximately 12 miles of high pressure transmission pipeline providing takeaway capacity for processed natural gas in northwestern North Dakota. The project is expected to be completed in the fourth quarter. The company believes it is in a good position to provide similar services for other natural gas processing facilities in the area.
• The company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. The company continues to see strong interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by 125 MMcf per day. The company has received commitment on approximately 30 percent of the total potential project and is moving forward on this phase with a projected in-service date of November 2011, subject to regulatory approval.

Electric and Natural Gas Utilities
Electric
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2010			2009			2010			2009
	(Dollars in millions, where applicable)
Operating revenues	$	56.2		$	48.5		$	211.6		$	196.2
Operating expenses:
Fuel and purchased power		17.8			16.6			63.1			65.7
Operation and maintenance		16.8			15.4			63.8			60.7
Depreciation, depletion and amortization		7.8			6.4			27.3			24.7
Taxes, other than income		2.0			1.4			9.1			8.4
		44.4			39.8			163.3			159.5
Operating income		11.8			8.7			48.3			36.7
Earnings	$	6.8		$	5.6		$	28.9		$	24.1
Retail sales (million kWh)		728.7			688.4			2,785.7			2,663.5
Sales for resale (million kWh)		7.2			46.7			58.3			90.8
Average cost of fuel and purchased power per kWh	$	.023		$	.022		$	.021		$	.023
Natural Gas Distribution
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2010			2009			2010			2009
	(Dollars in millions)
Operating revenues	$	289.2		$	328.0		$	892.7		$	1,072.8
Operating expenses:
Purchased natural gas sold		195.0			228.6			589.3			757.6
Operation and maintenance		34.6			35.2			137.4			140.5
Depreciation, depletion and amortization		10.9			10.6			43.0			42.7
Taxes, other than income		12.8			13.6			47.3			55.1
		253.3			288.0			817.0			995.9
Operating income		35.9			40.0			75.7			76.9
Earnings	$	23.6		$	21.0		$	37.0		$	30.8
Volumes (MMdk):
Sales		33.9			37.4			95.5			102.7
Transportation		37.1			37.1			135.8			132.7
Total throughput		71.0			74.5			231.3			235.4
Degree days (% of normal)*
Montana-Dakota		99	%		107	%		98	%		104	%
Cascade		96	%		106	%		96	%		105	%
Intermountain		95	%		112	%		100	%		107	%
* Degree days are a measure of the daily temperature-related demand for energy for heating.

The combined utility businesses reported earnings of $65.9 million, compared to earnings of $54.9 million in 2009. The increase in earnings reflects higher electric retail sales margins and volumes, an income tax benefit of $4.8 million, as well as higher nonregulated energy-related services, partially offset by decreased natural gas retail sales volumes.

Fourth quarter combined utility earnings were $30.4 million, compared to $26.6 million for the same period in 2009. The earnings increase reflects an income tax benefit of $4.8 million, as well as higher electric retail sales margins and volumes. Partially offsetting these increases were decreased natural gas retail sales volumes and increased depreciation, depletion and amortization expense.

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

• The company continues to realize efficiencies and enhanced service levels through its efforts to standardize operations, share services and consolidate back-office functions among its four utility companies.
• In April, the company filed an application with the North Dakota Public Service Commission for an electric rate increase of $15.4 million annually, or 14 percent above current rates. The requested increase included the investment in infrastructure upgrades, recovery of the investment in renewable generation, the costs associated with the Big Stone II plant and the significant loss of wholesale sales margins. An interim increase of $7.6 million annually was effective June 18. In June, a partial settlement agreement was filed related to cost of capital and capital structure. In July, the company filed an amendment to its application because of a settlement agreement providing for separate recovery of the costs associated with Big Stone II. In November, the company and the NDPSC Advocacy Staff filed a settlement agreement resolving certain issues. The company revised its requested increase to $8.8 million annually, or 7.7 percent, as a result of the settlements, the exclusion of the Big Stone II plant development costs, and other adjustments. A hearing on the application was held the week of Nov. 8. An order is anticipated in the first quarter of this year.
• In August, the company filed an application with the Montana Public Service Commission for an electric rate increase of $5.5 million annually, or 13 percent above current rates. The requested increase included the investment in infrastructure upgrades, recovery of the investment in renewable generation, the costs associated with the Big Stone II plant and the significant loss of wholesale sales margins. Montana-Dakota requested an interim increase of $3.1 million or approximately 7.4 percent, which is pending before the MTPSC. A hearing on the application is scheduled for Feb. 28.
• The company is analyzing potential projects for accommodating load growth and replacing purchased power contracts with company-owned generation. The company is reviewing the construction of natural gas-fired combustion.
• The company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major metropolitan areas. The company has signed a contract to develop a 30-mile high-voltage power line in southeast North Dakota to move power to the electric grid from a proposed 150-MW wind farm. The project will total approximately $20 million and will include substation upgrades. Pending regulatory approval, construction is expected to begin in 2011. The company’s customers will not bear any of the costs associated with the project as costs will be recovered through an approved interconnect tariff.
• The South Dakota Board of Minerals and Environment has approved rules implementing the South Dakota Regional Haze Program that upon approval by the EPA will require the Big Stone Station to install and operate a best available retrofit technology (BART) air quality control system to reduce emissions of particulate matter, sulfur dioxide, and nitrogen oxides as early as January 2016. The company’s share of the cost of this air quality control system could exceed $100 million. At this time the company believes continuing to operate Big Stone with the upgrade is the best option; however, the company will continue to review alternatives. The company intends to seek recovery of costs related to the above matter in electric rates charged to customers.

Construction
Construction Materials and Contracting
	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2010		2009			2010		2009
	(Dollars in millions)
Operating revenues	$	321.1	$	320.2		$	1,445.1	$	1,515.1
Operating expenses:
Operation and maintenance		284.0		287.4			1,260.4		1,292.0
Depreciation, depletion and amortization		21.1		22.5			88.3		93.6
Taxes, other than income		6.8		7.4			33.4		36.2
		311.9		317.3			1,382.1		1,421.8
Operating income		9.2		2.9			63.0		93.3
Earnings (loss)	$	3.8	$	(.7	)	$	29.6	$	47.1
Sales (000's):
Aggregates (tons)		5,384		4,979			23,349		23,995
Asphalt (tons)		1,203		1,199			6,279		6,360
Ready-mixed concrete (cubic yards)		627		720			2,764		3,042

The construction materials and contracting segment reported earnings of $29.6 million, compared to $47.1 million for 2009. The decrease in earnings reflects lower asphalt oil, ready-mixed concrete and asphalt margins and volumes, as well as decreased construction margins. Partially offsetting the decreases were lower selling, general and administrative costs, and higher gains on the sale of property, plant and equipment.

This segment reported fourth quarter earnings of $3.8 million compared to a loss of $700,000 for the same period in 2009. The increase in earnings was largely the result of lower selling, general and administrative costs, as well as higher gains on the sale of property, plant and equipment. Partially offsetting these increases were lower construction and product margins.

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

• Work backlog as of Dec. 31 was approximately $420 million, with 94 percent of construction backlog being public work and private representing 6 percent. In the company’s peak earnings year of 2006, private backlog represented 40 percent of construction backlog. Total backlog at Dec. 31, 2009, was $459 million.
• Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and harbor deepening projects.
• The company was recently identified as the apparent low bidder on the Port of Long Beach expansion. Upon final bid approval, the company’s share of the project for this phase is expected to exceed $30 million. This project is not included in the Dec. 31 backlog.
• As a result of the continued slow recovery in the residential and commercial markets and uncertainty in federal and state transportation funding, the company expects overall 2011 volumes and margins to be comparable to 2010.
• However, the company has several significant multi-year projects it will place bids on in 2011 including a light rail project in Hawaii, work on a Texas military base and a major expansion of a computer chip manufacture facility in Oregon. The company also expects to place a new asphalt oil terminal into service in late 2011 in Wyoming.
• Federal transportation stimulus of $7.9 billion was directed to states where the company operates. Of that amount, 63 percent was spent as of year end, with the majority of the remaining $2.9 billion to be spent during the remainder of 2011.
• The company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets.
• The company has a strong emphasis on operational efficiencies and cost reduction. SG&A expenses are down 38 percent in 2010 as compared to 2006, the peak earnings year for this segment.
• As the country’s 6^th largest sand and gravel producer, the company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.

Construction Services
	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2010		2009		2010		2009
	(In millions)
Operating revenues	$	237.3	$	167.1	$	789.1	$	819.0
Operating expenses:
Operation and maintenance		213.6		153.8		719.7		736.3
Depreciation, depletion and amortization		2.9		2.8		12.1		12.8
Taxes, other than income		5.5		4.6		23.9		25.7
		222.0		161.2		755.7		774.8
Operating income		15.3		5.9		33.4		44.2
Earnings	$	8.9	$	2.7	$	18.0	$	25.6

This segment had earnings of $18.0 million in 2010 compared to $25.6 million in 2009. This decrease reflects lower construction workloads and margins in the Western and Central regions, partially offset by higher workloads and margins in the Mountain region. Lower general and administrative expenses, including lower payroll-related costs, also partially offset the earnings decrease.

Fourth quarter earnings for this segment were $8.9 million, compared to $2.7 million for the comparable prior period. The increase in earnings was largely the result of higher construction workloads and margins in the Western region.

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

• Work backlog as of Dec. 31 was approximately $373 million, which is comparable to the Dec. 31, 2009 backlog, and $56 million higher than the Sept. 30 backlog of $317 million. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.
• As a result of the continued slow economic recovery, the company anticipates margins in 2011 to be comparable to 2010 levels.
• The company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction, governmental facilities, refinery turnaround projects and utility service work.
• The company continues to focus on costs and efficiencies to enhance margins. SG&A expenses are down 31 percent in 2010 as compared to 2008, the peak earnings year for this segment.
• With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure.

Other
	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2010			2009		2010			2009
	(In millions)
Operating revenues	$	.9		$	1.4	$	7.7		$	9.5
Operating expenses:
Operation and maintenance		(.7	)		.6		4.8			8.1
Depreciation, depletion and amortization		.4			.3		1.6			1.3
Taxes, other than income		.2			.1		.5			.3
		(.1	)		1.0		6.9			9.7
Operating income (loss)		1.0			.4		.8			(.2	)
Income from continuing operations		16.0			2.5		21.0			7.3
Loss from discontinued operations, net of tax		(3.3	)		---		(3.3	)		---
Earnings	$	12.7	*	$	2.5	$	17.7	*	$	7.3
* Includes a gain on the sale of the Brazilian transmission lines of $13.8 million (after tax).

Earnings for the year were $17.7 million, which includes the fourth quarter gain on the sale of the Brazilian transmission lines of $13.8 million (after tax), partially offset by a loss from discontinued operations of $3.3 million (after tax). The loss from discontinued operations is the result of expenses related to a guarantee of a construction contract by the domestic power production business, which was sold in 2007.

Use of Non-GAAP Financial Measures
Where noted in the press release, the company, in addition to presenting its earnings information in conformity with Generally Accepted Accounting Principles (GAAP), has provided non-GAAP earnings data that reflect adjustments to exclude a third quarter 2010 $16.5 million after-tax charge related to an arbitration ruling, a fourth quarter 2010 $13.8 million after-tax gain on the sale of its Brazilian transmission lines and a first quarter 2009 $384.4 million after-tax noncash charge related to a "ceiling test" charge. The company believes that these non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. Also, the company’s management uses these non-GAAP financial measures as indicators for planning and forecasting future periods. The presentation of this additional information is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.

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

• The company’s natural gas and oil production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, which are subject to various external influences that cannot be controlled.
• The regulatory approval, permitting, construction, startup and operation of power generation facilities may involve unanticipated changes or delays that could negatively impact the company’s business and its results of operations and cash flows.
• Economic volatility affects the company’s operations, as well as the demand for its products and services and the value of its investments and investment returns including its pension and other postretirement benefit plans and, may have a negative impact on the company’s future revenues and cash flows.
• The company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the company’s control. If the company is unable to obtain economic financing in the future, the company’s ability to execute its business plans, make capital expenditures or pursue acquisitions that the company may otherwise rely on for future growth could be impaired. As a result, the market value of the company’s common stock may be adversely affected. If the company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders.
• The company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the company’s customers and counterparties.
• The backlogs at the company’s construction services and construction materials and contracting businesses are subject to delay or cancellation and may not be realized.
• Actual quantities of recoverable natural gas and oil reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts.
• The company’s operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the company to environmental liabilities.
• Global climate change initiatives to reduce greenhouse gas emissions could adversely impact the company’s electric generation operations.
• The company's coalbed natural gas operations could be adversely impacted by the outcome of lawsuits challenging its coalbed natural gas development.
• The company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party’s ability to acquire the company.
• The value of the company’s investments in foreign operations may diminish due to political, regulatory and economic conditions and changes in currency exchange rates in countries where the company does business.
• Weather conditions can adversely affect the company’s operations and revenues and cash flows.
• Competition is increasing in all of the company’s businesses.
• The company could be subject to limitations on its ability to pay dividends.
• An increase in costs related to obligations under multi-employer pension plans could have a material negative effect on the company’s results of operations and cash flows.
• Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include:
  • Acquisition, disposal and impairments of assets or facilities.
  • Changes in operation, performance and construction of plant facilities or other assets.
  • Changes in present or prospective generation.
  • The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings.
  • The availability of economic expansion or development opportunities.
  • Population growth rates and demographic patterns.
  • Market demand for, and/or available supplies of, energy- and construction-related products and services.
  • The cyclical nature of large construction projects at certain operations.
  • Changes in tax rates or policies.
  • Unanticipated project delays or changes in project costs, including related energy costs.
  • Unanticipated changes in operating expenses or capital expenditures.
  • Labor negotiations or disputes.
  • Inability of the various contract counterparties to meet their contractual obligations.
  • Changes in accounting principles and/or the application of such principles to the company.
  • Changes in technology.
  • Changes in legal or regulatory proceedings.
  • The ability to effectively integrate the operations and the internal controls of acquired companies.
  • The ability to attract and retain skilled labor and key personnel.
  • Increases in employee and retiree benefit costs and funding requirements.

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

MDU Resources Group, Inc.
	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2010			2009		2010			2009
	(In millions, except per share amounts) (Unaudited)
Operating revenues	$	1,042.6		$	1,016.5	$	3,909.7		$	4,176.5
Operating expenses:
Fuel and purchased power		17.8			16.6		63.1			65.7
Purchased natural gas sold		185.4			219.2		567.8			739.7
Operation and maintenance		585.5			538.6		2,375.9			2,407.1
Depreciation, depletion and amortization		83.8			77.3		328.8			330.5
Taxes, other than income		39.9			37.3		163.4			166.6
Write-down of natural gas and oil properties		---			---		---			620.0
		912.4			889.0		3,499.0			4,329.6
Operating income (loss)		130.2			127.5		410.7			(153.1	)
Earnings from equity method investments		23.8			2.3		30.8			8.5
Other income		1.1			2.3		8.0			9.3
Interest expense		21.1			21.4		83.0			84.1
Income (loss) before income taxes		134.0			110.7		366.5			(219.4	)
Income taxes		41.7			38.1		122.5			(96.1	)
Income (loss) from continuing operations		92.3			72.6		244.0			(123.3	)
Loss from discontinued operations, net of tax		(3.3	)		---		(3.3	)		---
Net income (loss)		89.0			72.6		240.7			(123.3	)
Dividends on preferred stocks		.2			.1		.7			.7
Earnings (loss) on common stock	$	88.8		$	72.5	$	240.0		$	(124.0	)
Earnings (loss) per common share – basic:
Earnings (loss) before discontinued operations	$	.49		$	.39	$	1.29		$	(.67	)
Discontinued operations, net of tax		(.02	)		---		(.01	)		---
Earnings (loss) per common share – basic	$	.47		$	.39	$	1.28		$	(.67	)
Earnings (loss) per common share – diluted:
Earnings (loss) before discontinued operations	$	.49		$	.38	$	1.29		$	(.67	)
Discontinued operations, net of tax		(.02	)		---		(.02	)		---
Earnings (loss) per common share – diluted	$	.47		$	.38	$	1.27		$	(.67	)
Dividends per common share	$	.1625		$	.1575	$	.6350		$	.6225
Weighted average common shares outstanding – basic		188.3			187.7		188.1			185.2
Weighted average common shares outstanding – diluted		188.4			188.4		188.2			185.2

Note: Twelve months ended Dec. 31, 2010 results reflect the effects of a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax, or $.09 per common share), as well as a gain on the sale of the Brazilian transmission assets of $22.7 million ($13.8 million after tax, or $.07 per common share). Twelve months ended Dec. 31, 2009 results reflect the effects of a $384.4 million after-tax, or $2.07 per common share, noncash charge relating to the write-down of natural gas and oil properties.

	Twelve Months Ended
	December 31,
	2010			2009
	(Unaudited)
Other Financial Data
Book value per common share	$	14.22		$	13.61
Market price per common share	$	20.27		$	23.60
Dividend yield (indicated annual rate)		3.2	%		2.7	%
Price/earnings ratio*		16.0	x		N/A
Market value as a percent of book value		142.5	%		173.4	%
Return on average common equity*		9.1	%		(4.9	)%
Total assets**	$	6.3		$	6.0
Total equity**	$	2.7		$	2.6
Total debt **	$	1.5		$	1.5
Capitalization ratios:
Total equity		64	%		63	%
Total debt		36			37
		100	%		100	%

* Represents 12 months ended
**In billions