exhibit99.htm

EX-99 2 exhibit99.htm MDU EXHIBIT 99 12-31-08 exhibit99.htm

MDU Resources Reports 2008 Earnings and Initiates 2009 Earnings Guidance

BISMARCK, N.D. – Feb. 3, 2009 – MDU Resources Group, Inc. (NYSE:MDU) announced 2008 consolidated earnings from continuing operations of $293.0 million, or $1.59 per common share, including the effect of an $84.2 million after-tax noncash charge attributable to low energy prices on Dec. 31, 2008 at its natural gas and oil operations.

Absent the noncash charge, earnings from continuing operations would have been a record $377.2 million, or $2.05 per common share. This compares with earnings from continuing operations of $322.1 million for 2007, or $1.76 per common share.

“The noncash charge recorded in 2008 had no significant effect on our strong financial position,” said Terry D. Hildestad, president and chief executive officer of MDU Resources. “We had a strong year, particularly considering the state of the nation’s economy.”

Highlights

·	Consolidated earnings from continuing operations of $293.0 million.

·	Excluding the effect of a noncash charge, consolidated earnings from continuing operations of $377.2 million, up 17 percent from $322.1 million in 2007.

·	Record operating cash flows of approximately $785 million.

·	Initial earnings guidance for 2009 of $1.05 to $1.30 per common share.

In the fourth quarter of 2008 the company had a consolidated loss of $11.4 million, or 6 cents per common share, which includes the effect of the $84.2 million after-tax noncash charge as previously mentioned. Absent the charge, fourth quarter 2008 earnings totaled $72.8 million, or 40 cents per common share, compared to earnings of $94.6 million, or 52 cents per common share, for 2007.

“We are well positioned financially,” Hildestad said. “We have a strong balance sheet where debt represents 39 percent of our capital structure, and we have access to capital. Record operating cash flows allowed us to continue our growth by investing $1.3 billion into our diversified group of companies, without needing to raise equity in the public markets. We nearly tripled our utility rate base over the past two years leading to record earnings at this business of $53.5 million, and we grew our proved natural gas and oil reserves by 15 percent in 2008. We are well positioned to take advantage of proposed government sponsored stimulus plans with our 1.1 billion tons of strategic aggregate reserves and are further expanding our natural gas pipeline system in 2009. We believe that these factors, coupled with the dynamic workforce at our construction services business, position us to continue delivering long-term value to our shareholders.”

The company is initiating guidance for 2009 in the range of $1.05 to $1.30 per common share. This reflects significantly lower natural gas and oil prices, which have retreated to about one-third of the historically high prices experienced mid-year 2008.

The company, like many independent exploration and production companies, uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, the company is required to perform quarterly “ceiling tests” to compare the present value of future net cash flow from proved reserves based on spot market prices that exist on the last day of the period (cost ceiling) to the book value of those reserves at the balance sheet date. If the book value of the reserves exceeds the cost ceiling, a permanent noncash charge must be recorded. The significant decline in natural gas and oil prices as of Dec. 31, 2008 resulted in the charge.

The Securities and Exchange Commission has recently issued new rules regarding “ceiling test” pricing, which implement the use of 12-month-average pricing rather than single point-in-time period end pricing. The new rules are effective for reports filed on or after Jan. 1, 2010. Under the new rules, the company’s future net cash flows from proved reserves would have greatly exceeded the book value of the reserves and a noncash charge would not have been recorded.

MDU Resources’ natural gas and oil production business increased production by 7 percent to a record level during 2008. The increase was driven by the acquisition of producing properties and reserves in East Texas, and exploration activities in the Bakken and Paradox Basin areas. This business also grew natural gas and oil proved reserves to record levels. The East Texas acquisition, coupled with development of the company’s existing properties resulted in growth of proved reserves to 810 Bcfe at Dec. 31, a 15 percent increase in reserves compared to proved reserves of 707 Bcfe at Dec. 31, 2007. Although capital expenditures in 2009 will be reduced to reflect lower natural gas and oil prices, production is expected to be comparable to 2008.

The pipeline and energy services segment had record throughput and recently completed two pipeline expansions. The expansions included an increase of 32 million cubic feet per day in northwestern North Dakota to serve demand associated with the developing Bakken area. In 2009, the company is expanding its Grasslands Pipeline by 75,000 Mcf per day to ultimate full capacity.

The utility business had record earnings in 2008. The acquisitions of Cascade Natural Gas Corp. in 2007, and Intermountain Gas Company in 2008, have nearly tripled the size of MDU Resources’ utility business. That segment now operates a geographically continuous, regional utility business that stretches across eight states, from Minnesota to the West Coast, and serves more than 930,000 natural gas and electric customers. This business expects to further expand its rate-based generation in the next couple of years including the addition of 30 MW of wind generation in 2009.

The construction services group increased earnings 14 percent to a record level. Increased construction workloads and equipment sales and rentals contributed to the growth. To offset softening in some markets, the business continues to focus on costs and efficiencies that enhance margins and shifting of resources to take advantage of profitable opportunities.

The economy’s impact on construction continued to affect the construction materials and contracting business with decreased earnings, workloads and product volumes. However, an increase in public works projects combined with reduced operating costs and lower diesel costs is expected to result in higher earnings in 2009.

“We expect to continue to benefit from our diversified business strategy and prudent financial management,” Hildestad said. “We have adjusted our 2009 capital budget, all of which is expected to be funded by cash generated by operations. We provide products and services that are essential to our nation’s economy and we anticipate there will be growth opportunities for well-positioned companies such as ours during the current economic environment. Our long-term outlook continues to be strong considering our solid asset base including substantial natural gas, oil and aggregate reserves, generating facilities and pipelines, and the advantages our utility companies provide through reliable and predictable earnings and cash flows.”

The company will host a webcast at 1 p.m. EST today 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 for international callers, (706) 645-9291, conference ID 78354511.

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, operating in three core lines of business: energy, utility resources and construction materials. MDU Resources includes natural gas and oil production, natural gas pipelines and energy services, electric and natural gas utilities, construction services and construction materials and contracting. 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:

Vernon A. Raile, executive vice president, treasurer and chief financial officer, (701) 530-1003

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

Media:

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

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	2008 Earnings (In Millions)			2007 Earnings (In Millions)
Energy
Natural gas and oil production	$	122.3	*	$	142.5
Pipeline and energy services		26.4			31.4
Utility Resources
Electric and natural gas utilities		53.5			31.7
Construction services		49.8			43.8
Construction Materials and Contracting		30.2			77.0
Other		10.8			(4.3	)
Earnings before discontinued operations		293.0	*		322.1
Income from discontinued operations, net of tax		---			109.3
Earnings on common stock	$	293.0	*	$	431.4

* Reflects an $84.2 million after-tax noncash charge.

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

·	Earnings per common share for 2009, diluted, are projected in the range of $1.05 to $1.30. The company expects the percentage of 2009 earnings per common share by quarter to be in the following approximate ranges:

o	First quarter – 15 percent to 20 percent

o	Second quarter – 15 percent to 20 percent

o	Third quarter – 35 percent to 40 percent

o	Fourth quarter – 25 percent to 30 percent

·	While 2009 earnings per share is projected to decline compared to 2008 earnings, long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.

·	Estimated capital expenditures for 2009 are noted as follows and are expected to be funded by cash generated by operations. Capital expenditures for 2008 included the acquisition of natural gas production assets in East Texas and the Intermountain acquisition.

Business Line	Capital Expenditures 2009 Estimated (In Millions)			Capital Expenditures 2008 Actual (In Millions)
Natural gas and oil production	$	300		$	711
Pipeline and energy services		47			43
Electric		165			73
Natural gas distribution		55			398
Construction services		20			24
Construction materials and contracting		20			128
Other		3			1
Net proceeds		(8	)		(87	)
Total Capital Expenditures	$	602		$	1,291	*

* Includes $624.5 million for completed acquisitions.

Energy

Natural Gas and Oil Production

	Three Months Ended December 31,					Twelve Months Ended December 31,
	2008			2007		2008		2007
	(Dollars in millions, where applicable)
Operating revenues:
Natural gas	$	103.7		$	97.7	$	482.8	$	374.1
Oil		30.6			47.9		229.3		140.1
Other		---			.2		.2		.6
		134.3			145.8		712.3		514.8
Operating expenses:
Purchased natural gas sold		---			---		.1		.3
Operation and maintenance:
Lease operating costs		23.5			18.1		82.0		66.9
Gathering and transportation		6.3			5.5		24.8		20.4
Other		7.8			8.3		41.0		34.6
Depreciation, depletion and amortization		44.7			34.7		170.2		127.4
Taxes, other than income:
Production and property taxes		9.3			10.1		54.7		36.7
Other		.1			.2		.8		.8
Write-down of natural gas and oil properties		135.8			---		135.8		---
		227.5			76.9		509.4		287.1
Operating income (loss)		(93.2	)		68.9		202.9		227.7
Earnings (loss)	$	(57.5	)	$	43.5	$	122.3	$	142.5

Production:
Natural gas (MMcf)		16,177			16,262		65,457		62,798
Oil (MBbls)		741			655		2,808		2,365
Total Production (MMcfe)		20,619			20,189		82,303		76,988
Average realized prices (including hedges):
Natural gas (per Mcf)	$	6.41		$	6.01	$	7.38	$	5.96
Oil (per barrel)	$	41.43		$	73.14	$	81.68	$	59.26
Average realized prices (excluding hedges):
Natural gas (per Mcf)	$	5.07		$	5.43	$	7.29	$	5.37
Oil (per barrel)	$	41.13		$	74.06	$	82.28	$	59.53
Average depreciation, depletion and amortization rate, per equivalent Mcf	$	2.10		$	1.65	$	2.00	$	1.59
Production costs, including taxes, per equivalent Mcf:
Lease operating costs	$	1.14		$	.90	$	1.00	$	.87
Gathering and transportation		.31			.27		.30		.26
Production and property taxes		.45			.50		.66		.48
	$	1.90		$	1.67	$	1.96	$	1.61

2008		2007
Natural Gas	Oil		Natural Gas	Oil
(MMcf/MBbls)

Production by region:
Rocky Mountain	47,504	1,698	48,832	1,287
Mid-Continent/Gulf States	14,666	890	9,602	727
Offshore Gulf of Mexico	3,287	220	4,364	351
Total Production	65,457	2,808	62,798	2,365

Earnings at this segment were $206.5 million for 2008, excluding the effect of a noncash charge of $84.2 million after-tax, compared to earnings of $142.5 million for 2007. Average realized natural gas prices were 24 percent higher and average realized oil prices were 38 percent higher. Combined natural gas and oil production increased 7 percent over the previous year. Partially offsetting these increases were higher depreciation, depletion and amortization expense, production taxes and lease operating costs.

Fourth quarter earnings were $26.7 million, excluding the effect of the previously mentioned noncash charge of $84.2 million after-tax, compared to earnings of $43.5 million for the same period in 2007. Average realized oil prices for the fourth quarter were 43 percent lower than the comparable prior period. Also contributing to the decrease were higher depreciation, depletion and amortization expense and higher lease operating costs. Partially offsetting these decreases were higher average realized natural gas prices of 7 percent and an oil production increase of 13 percent.

The company’s combined proved natural gas and oil reserves as of Dec. 31 were 810 Bcfe, which included 205 Bcfe of reserve additions through acquisition and the drillbit and 20 Bcfe of negative reserve revisions. This resulted in the company having a reserve replacement ratio of 225 percent for 2008.

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

·	As the result of lower natural gas and oil prices, the company is managing its capital expenditures within its expected operating cash flows. At this level of investment, the company expects its combined natural gas and oil production in 2009 to be comparable to 2008 levels.

·	Earnings guidance reflects estimated natural gas prices for February through December as follows:

Index*	Price/Thousand Cubic Feet (Mcf)
Ventura	$4.75 to $5.25
NYMEX	$5.25 to $5.75
CIG	$3.25 to $3.75

·	Earnings guidance reflects estimated NYMEX crude oil prices for February through December in the range of $45 to $50 per barrel.

For 2009, the company has hedged approximately 40 percent to 45 percent of its estimated natural gas production. For 2010 and 2011, the company has hedged less than 5 percent of its estimated natural gas production. The hedges that are in place as of Feb. 2 for 2009 through 2011 are summarized in the following chart:

Commodity	Type	Index*	Period Outstanding	Forward Notional Volume (MMBtu/Bbl)	Price (Per MMBtu/Bbl)
Natural Gas	Swap	CIG	1/09 - 3/09	225,000	$8.45
Natural Gas	Swap	HSC	1/09 - 12/09	2,482,000	$8.16
Natural Gas	Collar	Ventura	1/09 - 12/09	1,460,000	$7.90-$8.54
Natural Gas	Collar	Ventura	1/09 - 12/09	4,380,000	$8.25-$8.92
Natural Gas	Swap	Ventura	1/09 - 12/09	3,650,000	$9.02
Natural Gas	Collar	CIG	1/09 - 12/09	3,650,000	$6.50-$7.20
Natural Gas	Swap	CIG	1/09 - 12/09	912,500	$7.27
Natural Gas	Collar	NYMEX	1/09 - 12/09	1,825,000	$8.75-$10.15
Natural Gas	Swap	Ventura	1/09 - 12/09	3,650,000	$9.20
Natural Gas	Collar	NYMEX	1/09 - 12/09	3,650,000	$11.00-$12.78
Natural Gas	Basis	NYMEX to Ventura	1/09 - 12/09	3,650,000	$0.61
Natural Gas	Swap	HSC	1/10 - 12/10	1,606,000	$8.08
Natural Gas	Swap	HSC	1/11 - 12/11	1,350,500	$8.00

*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.

Pipeline and Energy Services

	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2008		2007			2008		2007
	(Dollars in millions)
Operating revenues	$	108.7	$	119.3		$	532.2	$	447.1
Operating expenses:
Purchased natural gas sold		65.5		75.5			373.9		291.7
Operation and maintenance		22.4		17.9			73.8		65.6
Depreciation, depletion and amortization		6.3		5.6			23.6		21.7
Taxes, other than income		2.8		1.9			11.3		10.1
		97.0		100.9			482.6		389.1
Operating income		11.7		18.4			49.6		58.0
Income from continuing operations		6.7		10.3			26.4		31.4
Income (loss) from discontinued operations, net of tax		---		(.1	)		---		.1
Earnings	$	6.7	$	10.2		$	26.4	$	31.5

Transportation volumes (MMdk):
Montana-Dakota Utilities Co.*		8.3		7.6			32.0		29.3
Other		28.7		27.8			106.0		111.5
		37.0		35.4			138.0		140.8
Gathering volumes (MMdk)		25.8		24.2			102.1		92.4

* A public utility division of the company.

Earnings from continuing operations at the pipeline and energy services segment were $26.4 million, compared to $31.4 million reported in 2007. Contributing to the decrease were lower storage services revenue and a 31 percent decrease in volumes transported to storage, as well as higher operation and maintenance expenses, including higher payroll-related costs. Partially offsetting these decreases were a 10 percent increase in off-system transportation volumes and higher demand fees as well as higher gathering volumes and rates.

Fourth quarter earnings from continuing operations for 2008 were $6.7 million, compared to $10.3 million for the comparable prior period. Lower storage services revenue and higher operation and maintenance expenses were partially offset by increased gathering rates and volumes.

Recently, the company completed two pipeline expansions. With the addition of compression and a new interconnect with Northern Border in the Bakken area in northwest North Dakota, capacity was increased by 32,000 Mcf per day. Pipeline capacity in Eastern North Dakota was also increased by 10,500 Mcf per day.

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

An incremental expansion to the Grasslands Pipeline of 75,000 Mcf per day is in process with an in-service date of August, pending regulatory approval. Through additional compression, the firm capacity of the Grasslands Pipeline will reach ultimate full capacity of 213,000 Mcf per day, an increase from the current firm capacity of 138,000 Mcf per day.

·	In 2009, total gathering and transportation throughput is expected to be slightly higher than 2008 record levels.

·	The company continues to pursue expansion of facilities and services offered to customers.

Utility Resources

Electric and Natural Gas Utilities

Electric

	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2008		2007		2008		2007
	(Dollars in millions, where applicable)
Operating revenues	$	54.2	$	47.7	$	208.3	$	193.4
Operating expenses:
Fuel and purchased power		21.3		16.7		75.4		69.6
Operation and maintenance		17.4		16.1		64.8		61.7
Depreciation, depletion and amortization		6.0		5.7		24.0		22.5
Taxes, other than income		2.1		1.5		8.7		7.9
		46.8		40.0		172.9		161.7
Operating income		7.4		7.7		35.4		31.7
Earnings	$	3.6	$	4.7	$	18.7	$	17.7
Retail sales (million kWh)		717.2		656.2		2,663.4		2,601.7
Sales for resale (million kWh)		65.1		35.2		223.8		165.6
Average cost of fuel and purchased power per kWh	$	.027	$	.023	$	.025	$	.025

Natural Gas Distribution

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2008			2007			2008			2007
	(Dollars in millions, where applicable)
Operating revenues	$	383.0		$	252.8		$	1,036.1		$	533.0
Operating expenses:
Purchased natural gas sold		281.7			178.3			757.6			372.2
Operation and maintenance		41.0			30.7			123.6			88.5
Depreciation, depletion and amortization		10.9			7.0			32.6			19.0
Taxes, other than income		15.1			11.3			45.4			20.4
		348.7			227.3			959.2			500.1
Operating income		34.3			25.5			76.9			32.9
Earnings	$	16.3		$	13.0		$	34.8		$	14.0
Volumes (MMdk):
Sales		34.9			24.6			87.9			53.0
Transportation		33.6			25.7			103.5			54.7
Total throughput		68.5			50.3			191.4			107.7
Degree days (% of normal)*
Montana-Dakota		102.9	%		92.8	%		102.7	%		92.9	%
Cascade		103.7	%		101.7	%		108.0	%		101.7	%
Intermountain		90.3	%		---			90.3	%		---
Average cost of natural gas, including transportation, per dk**
Montana-Dakota	$	6.31		$	5.12		$	7.63		$	6.00
Cascade	$	9.64		$	7.80		$	8.48		$	7.75
Intermountain	$	8.83		$	---		$	8.83		$	---
* Degree days are a measure of the daily temperature-related demand for energy for heating.
** Regulated natural gas sales only.
Note: Cascade and Intermountain were acquired on July 2, 2007, and October 1, 2008, respectively.

The combined utility businesses reported record earnings of $53.5 million, compared to earnings of $31.7 million in 2007. The earnings increase is largely the result of the acquisitions of Cascade in July 2007 and Intermountain in October 2008. Also contributing to the increase were higher retail sales volumes and margins at existing operations.

Fourth quarter combined utility earnings were $19.9 million, compared to $17.7 million for the same period in 2007. The increase is primarily the result of the Intermountain acquisition.

The company recently announced its plans to develop additional wind generation including a 19.5 MW wind generation facility in southwest North Dakota. Also, an expansion project of 10.5 MW is planned at the Diamond Willow wind facility near Baker, Montana. Both projects are expected to be commercial late this year, pending regulatory approvals.

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

·	The company is negotiating the purchase of an ownership interest of 25 MW in the Wygen III power generation facility near Gillette, Wyoming. If acquired, this owned rate base generation will replace purchased power on its Wyoming system.

The company is analyzing potential projects for accommodating load growth and replacing an expired purchased power contract with company-owned generation, which will add to base-load capacity and rate base. The company is a participant in the Big Stone II project. On January 15, the Minnesota Public Utilities Commission voted to grant a transmission certificate of need and a route permit for the project with conditions. Details of the conditions will be included in the Commission’s final order expected to be provided by mid-February. If the decision is to proceed with construction of the plant, it is projected to be completed in 2015. The company anticipates it would own at least 116 megawatts of this plant. In the event the pending conditions are not acceptable, the company is reviewing alternatives, including the construction of certain natural gas-fired combustion generation, which would be rate-based.

·	In August, Montana-Dakota Utilities Co. filed an application with the Wyoming Public Service Commission for an electric rate increase. Montana-Dakota requested a total increase of $757,000 annually or approximately 4 percent more than current rates. An order is anticipated in the second quarter.

Construction Services

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2008		2007		2008		2007
	(In millions)
Operating revenues	$	296.7	$	309.3	$	1,257.3	$	1,103.2
Operating expenses:
Operation and maintenance		274.2		279.3		1,122.7		979.7
Depreciation, depletion and amortization		3.5		3.8		13.4		14.3
Taxes, other than income		7.9		8.9		39.7		33.7
		285.6		292.0		1,175.8		1,027.7
Operating income		11.1		17.3		81.5		75.5
Earnings	$	8.6	$	9.9	$	49.8	$	43.8

This segment had record earnings of $49.8 million in 2008, a 14 percent increase over the previous year's $43.8 million. Increased construction workloads as well as higher equipment sales and rentals were partially offset by lower construction margins.

Fourth quarter earnings for this segment were $8.6 million, compared to $9.9 million for the comparable prior period. The decrease is primarily the result of lower construction margins and workloads in certain regions.

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

·	The company anticipates margins in 2009 to be comparable to 2008.

·	The company continues to focus on costs and efficiencies to enhance margins. With its highly skilled technical workforce, this group is prepared to take advantage of potential future government stimulus spending on transmission infrastructure.

·	Work backlog as of Dec. 31 was approximately $604 million, compared to $827 million at Dec. 31, 2007.

·	This business continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.

Construction Materials and Contracting

	Three Months Ended December 31,				Twelve Months Ended December 31,
	2008		2007		2008		2007
	(Dollars in millions)
Operating revenues	$	392.0	$	438.8	$	1,640.7	$	1,761.5
Operating expenses:
Operation and maintenance		352.6		382.2		1,437.9		1,483.5
Depreciation, depletion and amortization		24.2		26.7		100.9		95.8
Taxes, other than income		8.0		10.1		39.1		43.6
		384.8		419.0		1,577.9		1,622.9
Operating income		7.2		19.8		62.8		138.6
Earnings	$	5.0	$	10.9	$	30.2	$	77.0

Sales (000's):
Aggregates (tons)		7,047		9,247		31,107		36,912
Asphalt (tons)		1,308		1,627		5,846		7,062
Ready-mixed concrete (cubic yards)		822		1,039		3,729		4,085

The construction materials and contracting segment reported earnings of $30.2 million, compared to $77.0 million for 2007. Construction workloads and margins, as well as product volumes from existing operations, were significantly lower as a result of the economic downturn primarily as it relates to the residential market. In addition, diesel fuel costs were substantially higher.

Fourth quarter earnings were $5.0 million, compared to $10.9 million for the same period in 2007. The decrease is largely the result of lower product volumes and margins, as previously discussed.

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

The economic slowdown and substantially higher energy prices adversely impacted operations in 2008. Although the company predicts that this economic slowdown will continue into 2009, it is expected that earnings will be higher than 2008 primarily the result of cost reduction measures put in place during 2008 and substantially lower diesel costs expected in 2009 compared to 2008.

·	The company continues its strong emphasis on cost containment throughout the organization. In addition, the company has strong market share in its markets and is well positioned to take advantage of potential future government stimulus spending on transportation infrastructure.

·	The company also is pursuing opportunities for expansion of its liquid asphalt materials business to cost effectively meet the liquid asphalt requirements of the company, as well as third-party customers.

Work backlog as of Dec. 31 was approximately $453 million, compared to $462 million at Dec. 31, 2007. The backlog includes the recent addition of several public works projects. Although public project margins tend to be somewhat lower than private construction-related work, the company anticipates significant contributions to revenue from an increase in public works volume.

·	As the country’s 8th largest aggregate producer, the company will continue to strategically manage its aggregate reserves in all its markets.

Other

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2008			2007			2008		2007
	(Dollars in millions)
Operating revenues	$	2.6		$	2.7		$	10.5	$	10.0
Operating expenses:
Operation and maintenance		(2.0	)		3.9			5.9		15.9
Depreciation, depletion and amortization		.3			.2			1.3		1.2
Taxes, other than income		.1			---			.4		.2
		(1.6	)		4.1			7.6		17.3
Operating income (loss)		4.2			(1.4	)		2.9		(7.3	)
Income (loss) from continuing operations		5.9			2.4			10.8		(4.3	)
Income from discontinued operations, net of tax		---			---			---		109.2
Earnings	$	5.9		$	2.4		$	10.8	$	104.9

In July 2007, the company closed on the sale of its domestic independent power production business. Earnings for 2007 reflect a $91.5 million gain on the sale of these assets.

Use of Non-GAAP Financial Measure

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 an adjustment to exclude a fourth quarter 2008 $84.2 million after-tax noncash charge related to a “ceiling-test” charge. The company believes that this non-GAAP financial measure is useful to investors because the item excluded is not indicative of the company’s continuing operating results. Also, the company’s management uses this non-GAAP financial measure as an indicator 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.

·	Since Dec. 31, spot market prices for both natural gas and oil have continued to be volatile. If lower prices continue, the company may have to record additional noncash charges relating to the ceiling test.

·	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, as a result, 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.

·	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.

One of the company’s subsidiaries is subject to ongoing litigation and administrative proceedings in connection with its coalbed natural gas development activities. These proceedings have caused delays in coalbed natural gas drilling activity, and 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 company's electric generation operations could be adversely impacted by global climate change initiatives to reduce greenhouse gas emissions.

·	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.

One of the company’s subsidiaries is engaged in litigation with a nonaffiliated natural gas producer that has been conducting drilling and production operations that the subsidiary believes is causing diversion and loss of quantities of storage gas from one of its storage reservoirs. If the subsidiary is not able to obtain relief through the courts or the regulatory process, its storage operations could be materially and adversely affected.

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

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

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

o	Acquisition, disposal and impairments of assets or facilities.

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

o	Changes in present or prospective generation.

o	The availability of economic expansion or development opportunities.

o	Population growth rates and demographic patterns.

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

o	The cyclical nature of large construction projects at certain operations.

o	Changes in tax rates or policies.

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

o	Unanticipated changes in operating expenses or capital expenditures.

o	Labor negotiations or disputes.

o	Inability of the various contract counterparties to meet their contractual obligations.

o	Changes in accounting principles and/or the application of such principles to the company.

o	Changes in technology.

o	Changes in legal or regulatory proceedings.

o	The ability to effectively integrate the operations and the internal controls of acquired companies.

o	The ability to attract and retain skilled labor and key personnel.

o	Increases in employee and retiree benefit costs.

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,
	2008			2007			2008		2007
	(In millions, except per share amounts) (Unaudited)

Operating revenues	$	1,295.8		$	1,232.7		$	5,003.3	$	4,247.9
Operating expenses:
Fuel and purchased power		21.3			16.7			75.4		69.6
Purchased natural gas sold		278.6			177.4			765.9		377.4
Operation and maintenance		736.1			754.7			2,948.1		2,788.5
Depreciation, depletion and amortization		95.9			83.7			366.0		301.9
Taxes, other than income		45.4			44.0			200.1		153.4
Write-down of natural gas and oil properties		135.8			---			135.8		---
		1,313.1			1,076.5			4,491.3		3,690.8
Operating income (loss)		(17.3	)		156.2			512.0		557.1
Earnings from equity method investments		.9			1.7			6.6		19.6
Other income		2.1			2.7			4.0		8.3
Interest expense		23.8			18.3			81.5		72.2
Income (loss) before income taxes		(38.1	)		142.3			441.1		512.8
Income taxes		(26.8	)		47.5			147.4		190.0
Income (loss) from continuing operations		(11.3	)		94.8			293.7		322.8
Income (loss) from discontinued operations, net of tax		---			(.1	)		---		109.3
Net income (loss)		(11.3	)		94.7			293.7		432.1
Dividends on preferred stocks		.1			.1			.7		.7
Earnings (loss) on common stock	$	(11.4	)	$	94.6		$	293.0	$	431.4

Earnings (loss) per common share -- basic
Earnings (loss) before discontinued operations	$	(.06	)	$	.52		$	1.60	$	1.77
Discontinued operations, net of tax		---			---			---		.60
Earnings (loss) per common share -- basic	$	(.06	)	$	.52		$	1.60	$	2.37
Earnings (loss) per common share -- diluted
Earnings (loss) before discontinued operations	$	(.06	)	$	.52		$	1.59	$	1.76
Discontinued operations, net of tax		---			---			---		.60
Earnings (loss) per common share -- diluted	$	(.06	)	$	.52		$	1.59	$	2.36
Dividends per common share	$	.1550		$	.1450		$	.6000	$	.5600
Weighted average common shares outstanding -- basic		183.6			182.4			183.1		181.9
Weighted average common shares outstanding -- diluted		183.6			183.3			183.8		182.9

Note: Three months and twelve months ended results reflect the effects of an $84.2 million after-tax, or 46 cents per common share, noncash charge relating to the write-down of natural gas and oil properties at December 31.

	Twelve Months Ended December 31,
	2008			2007
	(Unaudited)

Other Financial Data
Book value per common share	$	14.95		$	13.80
Market price per common share	$	21.58		$	27.61
Dividend yield (indicated annual rate)		2.9	%		2.1	%
Price/earnings ratio*		13.6	x		11.7	x
Market value as a percent of book value		144.3	%		200.1	%
Return on average common equity*		11.0	%		18.5	%
Total assets**	$	6.6		$	5.6
Total equity**	$	2.8		$	2.5
Total debt **	$	1.8		$	1.3
Capitalization ratios:
Total equity		61	%		66	%
Total debt		39			34
		100	%		100	%

* Represents 12 months ended

** In billions

Note: The above information reflects the effects of both continued and discontinued operations.