MDU RESOURCES GROUP INC - FORM 8-K - EX-99 - EXHIBIT 99

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8-K - MDU RESOURCES GROUP, INC. FORM 8-K - MDU RESOURCES GROUP INC	mduform8k.htm

MDU Resources Reports Second Quarter Earnings, Reaffirms 2012 Earnings Guidance


•	Consolidated earnings of $53.9 million, or 29 cents per share.


•	Oil production grows 32%.


•	Recently announced acquisition of 50 percent interest in natural gas and oil midstream assets.


•	Advance Determination of Prudence approved for Big Stone environmental upgrades.

BISMARCK, N.D. – Aug. 1, 2012 - MDU Resources Group, Inc. (NYSE:MDU) today reported second quarter consolidated earnings of $53.9 million, or 29 cents per common share, compared to $44.9 million, or 24 cents per common share for the second quarter of 2011. 2012 earnings reflect a benefit from the reversal of an arbitration charge of $15.0 million, or 8 cents per share, as a result of a favorable court ruling and $5.1 million of earnings, or 3 cents per share, from discontinued operations.

“We continued to deliver earnings at the upper range of our quarterly guidance, even before the benefit from reversing the arbitration charge and earnings from discontinued operations,” said Terry D. Hildestad, president and chief executive officer of MDU Resources. “Our investment in our exploration and production business continues to deliver impressive increases in oil production, and our construction businesses are seeing some signs of market improvements.”

Oil production increased by 32 percent compared to the same quarter last year and increased 13 percent from the first quarter, with three fourths of the growth coming from the company's Bakken acreage, where five of its rigs currently are drilling.

“Through the first half of the year Fidelity Exploration & Production has grown total oil production by 26 percent, and we are confident that we will achieve our original full-year production target. In fact, we have moved up the low end of our projected oil production growth and now expect a 25 percent to 30 percent increase over 2011,” Hildestad said. He noted that lower average realized oil prices and continuing low natural gas prices for the quarter impacted Fidelity's earnings, along with a strategic shift away from natural gas production until prices increase.

The pipeline and energy services business also felt the effect of low natural gas prices, as production decreases significantly impacted gathering. However, the business reported good progress in its effort to expand its midstream business. In May, the company announced it purchased a 50 percent undivided interest in natural gas and oil midstream assets near Belfield, N.D. serving the Bakken area. The facilities include a newly constructed, state-of-the-industry natural gas processing plant that has an inlet processing

capacity of 35 million cubic feet per day, oil terminal, natural gas and oil gathering systems and related facilities. In addition, engineering and design work, along with final economic analysis, are continuing on a diesel topping plant proposed by the company's pipeline and energy services group and Calumet Refining, LLC. The facility would be able to process up to 20,000 barrels per day of Bakken oil.

Unseasonably warm weather, primarily in April, affected heating season sales at the natural gas utility business segment. Overall natural gas sales declined 23 percent. This was principally the result of temperatures that were significantly warmer than the prior year across the entire service territory, including 36 percent warmer in the Plains states, 31 percent warmer in Idaho and 16 percent warmer in the Pacific Northwest. Electric retail sales increased 8 percent as a result of growth in small commercial and industrial and residential customers primarily driven by Bakken development.

The construction businesses experienced revenue expansion along with a combined earnings improvement of $5.4 million for the second quarter. The company's specialty equipment manufacturing and sales division realized higher revenue and earnings, and the Bakken -- where the construction group has a $58 million backlog -- continues to provide good growth opportunities. Warm weather in the North Central and Intermountain regions enabled an early start to the construction season.

“We are seeing encouraging signs that some of our construction markets may finally be stabilizing,” Hildestad said. “In addition, Congress recently passed a two-year transportation bill that continues level funding for highway programs at approximately $40 billion per year.

“Operationally our businesses are performing well, and they have overcome some significant pricing and weather challenges,” he said. “We are pleased with our progress at the midway point of 2012.”

Based on the company's projections for the remainder of 2012, annual earnings guidance is reaffirmed in the range of $1.00 to $1.25 per share.

The company will host a webcast at 11 a.m. EDT on Thursday, Aug. 2 to discuss earnings results and guidance. The event can be accessed at www.mdu.com. Webcast and audio replays will be available. The dial-in number for audio replay is (855) 859-2056, or (404) 537-3406 for international callers, conference ID 93978182.

About MDU Resources

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

Contacts

Financial:

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

Media:

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

Laura Lueder, corporate public relations manager, (701) 530-1095

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 Second Quarter 2012 (In Millions)				Earnings Second Quarter 2011 (In Millions)
Exploration and Production		$18.0				$21.3
Regulated
Electric and natural gas utilities	(2.0		)		6.7
Pipeline and energy services	15.8			*	4.8
Construction
Construction materials and contracting	7.8				5.0
Construction services	8.7				6.1
Other	.5				1.1
Earnings before discontinued operations	48.8				45.0
Income (loss) from discontinued operations, net of tax	5.1				(.1		)
Earnings on common stock		$53.9				$44.9
* Reflects a net benefit of $24.1 million ($15.0 million after tax) related to the natural gas gathering operations litigation.

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


•	Earnings per common share for 2012 are projected in the range of $1.00 to $1.25. The company expects the approximate percentage of 2012 earnings per common share by quarter to be:


◦	Third quarter - 35 percent


◦	Fourth quarter - 25 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.


•	Estimated capital expenditures for 2012 are approximately $920 million. The increase as compared to May projections is largely related to the acquisition of a 50 percent undivided interest in natural gas and oil midstream assets in the Bakken area, and increased investments in oil drilling and utility expansion in the Bakken area.

Exploration and Production



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(Dollars in millions, where applicable)
Operating revenues:
Oil	$	85.1	$	68.5	$	158.6	$	127.0
Natural gas	20.8		44.3		47.2		89.7
	105.9		112.8		205.8		216.7
Operating expenses:
Operation and maintenance:
Lease operating costs	19.0		18.4		37.5		36.4
Gathering and transportation	4.2		5.6		8.5		11.3
Other	9.5		9.2		18.7		17.5
Depreciation, depletion and amortization	34.4		33.4		71.2		67.6
Taxes, other than income:
Production and property taxes	8.7		10.5		18.3		20.5
Other	.3		.2		.6		.5
	76.1		77.3		154.8		153.8
Operating income	29.8		35.5		51.0		62.9
Earnings	$	18.0	$	21.3	$	30.9	$	37.6
Production:
Oil (MBbls)	1,085		821		2,042		1,623
Natural gas (MMcf)	8,239		11,253		18,286		23,011
Total production (MBOE)	2,458		2,696		5,090		5,458
Average realized prices (including hedges):
Oil (per barrel)	$	78.51	$	83.42	$	77.67	$	78.26
Natural gas (per Mcf)	$	2.52	$	3.94	$	2.58	$	3.90
Average realized prices (excluding hedges):
Oil (per barrel)	$	71.89	$	89.25	$	77.86	$	84.31
Natural gas (per Mcf)	$	1.46	$	3.49	$	1.72	$	3.44
Average depreciation, depletion and amortization rate, per BOE	$	13.32	$	11.76	$	13.32	$	11.76
Production costs, including taxes, per BOE:
Lease operating costs	$	7.74	$	6.83	$	7.37	$	6.67
Gathering and transportation	1.70		2.07		1.66		2.06
Production and property taxes	3.54		3.87		3.58		3.76
	$	12.98	$	12.77	$	12.61	$	12.49
Notes:
• Oil includes crude oil, condensate and natural gas liquids.
• Beginning with first quarter results, reporting barrel of oil equivalents rather than million cubic feet equivalents, based on a 6:1 ratio.

Earnings at this segment were $18.0 million for the second quarter of 2012, compared to $21.3 million in 2011. The earnings decrease reflects 36 percent lower average realized natural gas prices, decreased natural gas production of 27 percent, as well as 6 percent lower average realized oil prices. These decreases were partially offset by increased oil production of 32 percent, as well as lower production taxes. The combined oil and natural gas pricing earnings effect was a negative $12.6 million.

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


•	The company has increased its expected capital expenditures to approximately $475 million in 2012, up from $400 million. The company continues its focus on returns by allocating the majority of its capital investment into the production of oil given the current commodity price environment.

•

For 2012, the company now expects a 25 percent to 30 percent increase in oil production and a 25 percent to 30 percent decrease in natural gas production. The projected decline in natural gas production is primarily the result of a decision to curtail certain natural gas properties as well as divestments and the deferral of certain natural gas development activity because of sustained low natural gas prices.


•	The company has a total of nine drilling rigs deployed on its acreage in the Bakken, Texas, Paradox and other areas.


•	Bakken Area


◦	The company owns a total of approximately 124,000 net acres of leaseholds.


◦	Capital expenditures are expected to total approximately $215 million this year; an expansion of $115 million compared to 2011.


◦	Mountrail County, North Dakota


▪	The company owns approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations. The drilling of 20 operated wells and participation in various non-operated wells is expected for this year.


▪	Approximately 40 remaining middle Bakken locations have been identified. This does not include any additional Three Forks potential, which is currently being evaluated. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 Bbls.


◦	Stark County, North Dakota


▪	The company holds approximately 51,000 net exploratory leasehold acres, targeting the Three Forks formation. The drilling of 14 operated wells and participation in various non-operated wells is expected for this year.


▪	Based on current information and assuming 1280-acre spacing, the company has identified approximately 40 future drill sites. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.


◦	Richland County, Montana


▪	The company holds approximately 57,000 net exploratory leasehold acres, targeting the Three Forks formation. The drilling of 6 operated wells is planned for this year.


▪	Approximately 100 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.


•	Niobrara - southeastern Wyoming


◦	The company holds approximately 65,000 net exploratory leasehold acres.


◦	The drilling of 4 operated wells has been completed with approximately $25 million of capital expenditures. The economic viability of the Niobrara and other horizons is currently being evaluated.


◦	Approximately 200 potential gross well sites are available based on 640-acre spacing.


•	Paradox Basin - Cane Creek Federal Unit, Utah


◦	The company holds approximately 75,000 net exploratory leasehold acres.


◦	The drilling of 6 to 8 operated wells is planned for this year with approximately $50 million of capital expenditures.


◦	Approximately 70 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well range from 250,000 to 1,000,000 Bbls.


•	Texas


◦	The company is targeting areas that have the potential for higher liquids content with

approximately $60 million of capital planned for this year.


◦	Plans are to drill 13 operated wells in Texas this year and participate in some non-operated activity.


◦	Approximately 50 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.


•	Heath Shale


◦	The company holds approximately 90,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana and expects to drill 5 wells this year with capital of approximately $35 million.


•	Sioux County, Nebraska

◦

The company has entered into an exploration agreement where it will drill two vertical wells and one horizontal well during 2012. The first vertical well in the project has been drilled and is awaiting fracture stimulation, and the second vertical well is currently being drilled. The horizontal well is planned for the fourth quarter of this year. After evaluating these initial wells, the company may exercise an option to purchase a 65 percent working interest in approximately 79,000 gross acres.


•	Other Opportunities


◦	The remaining forecasted 2012 capital has been allocated to other operated and non-operated opportunities, including $25 million for acquisitions of leaseholds.


•	Earnings guidance reflects estimated oil and natural gas prices for August through December as follows:



Crude Oil Index: NYMEX	$85 to $95 per barrel
Natural Gas Index: NYMEX	$2.75 to $3.25 per Mcf

Note: Estimated prices do not reflect potential basis differentials.


•	For the last six months of 2012, the company has hedged approximately 55 percent to 60 percent of its estimated oil production and 60 percent to 65 percent of its estimated natural gas production. For 2013, the company has hedged 35 percent to 40 percent of its estimated oil production. The hedges that are in place as of Aug. 1 are summarized in the following chart:



Commodity	Type	Index	Period Outstanding	Forward Notional Volume (Bbl/MMBtu)	Price (Per Bbl/MMBtu)
Crude Oil	Collar	NYMEX	7/12 - 12/12	184,000	$80.00-$87.80
Crude Oil	Collar	NYMEX	7/12 - 12/12	184,000	$80.00-$94.50
Crude Oil	Collar	NYMEX	7/12 - 12/12	184,000	$80.00-$98.36
Crude Oil	Collar	NYMEX	7/12 - 12/12	92,000	$85.00-$102.75
Crude Oil	Collar	NYMEX	7/12 - 12/12	92,000	$85.00-$103.00
Crude Oil	Swap	NYMEX	7/12 - 12/12	92,000	$100.10
Crude Oil	Swap	NYMEX	7/12 - 12/12	92,000	$100.00
Crude Oil	Swap	NYMEX	7/12 - 12/12	184,000	$110.30
Crude Oil	Swap	NYMEX	7/12 - 12/12	184,000	$96.00
Crude Oil	Swap	NYMEX	7/12 - 12/12	184,000	$99.00
Natural Gas	Swap	NYMEX	7/12 - 12/12	1,748,000	$6.27
Natural Gas	Swap	NYMEX	7/12 - 12/12	920,000	$5.005
Natural Gas	Swap	NYMEX	7/12 - 12/12	460,000	$5.005
Natural Gas	Swap	NYMEX	7/12 - 12/12	460,000	$5.0125
Natural Gas	Swap	NYMEX	7/12 - 12/12	1,840,000	$3.05
Natural Gas	Swap	NYMEX	7/12 - 12/12	1,840,000	$2.805
Natural Gas	Swap	Ventura	7/12 - 12/12	1,840,000	$4.87
Crude Oil	Collar	NYMEX	1/13 - 12/13	182,500	$95.00-$117.00
Crude Oil	Collar	NYMEX	1/13 - 12/13	182,500	$95.00-$117.00
Crude Oil	Collar	NYMEX	1/13 - 12/13	365,000	$90.00-$97.05
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$95.00
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$95.30
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$100.00
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$100.02
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$102.00
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$102.00
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$104.00
Crude Oil	Swap	NYMEX	1/13 - 12/13	182,500	$104.00
Natural Gas	Basis Swap	CIG	7/12 - 12/12	1,380,000	$0.405
Natural Gas	Basis Swap	CIG	7/12 - 12/12	368,000	$0.41
Notes: ž Ventura is an index pricing point related to Northern Natural Gas Co.'s system; CIG is an index pricing point related to Colorado Interstate Gas Co.'s system. ž For all basis swaps, index prices are below NYMEX prices and are reported as a positive amount in the price column.

Regulated

Electric and Natural Gas Utilities



Electric
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(Dollars in millions, where applicable)
Operating revenues	$	53.0		$	50.0		$	110.9		$	107.8
Operating expenses:
Fuel and purchased power	15.2			14.5			33.6			31.4
Operation and maintenance	19.1			18.3			35.3			34.3
Depreciation, depletion and amortization	8.0			7.9			16.1			16.1
Taxes, other than income	2.6			2.5			5.3			5.0
	44.9			43.2			90.3			86.8
Operating income	8.1			6.8			20.6			21.0
Earnings	$	4.4		$	4.8		$	12.0		$	13.3
Retail sales (million kWh)	666.3			614.6			1,436.0			1,409.3
Sales for resale (million kWh)	1.0			21.8			2.9			28.5
Average cost of fuel and purchased power per kWh	$	.021		$	.021		$	.022		$	.021

Natural Gas Distribution
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(Dollars in millions)
Operating revenues	$	116.8		$	164.6		$	424.7		$	535.0
Operating expenses:
Purchased natural gas sold	62.9			102.0			262.2			359.4
Operation and maintenance	35.9			33.3			71.1			67.6
Depreciation, depletion and amortization	11.3			11.2			22.5			22.4
Taxes, other than income	10.0			10.6			26.2			28.4
	120.1			157.1			382.0			477.8
Operating income (loss)	(3.3		)	7.5			42.7			57.2
Earnings (loss)	$	(6.4	)	$	1.9		$	19.1		$	29.4
Volumes (MMdk):
Sales	13.4			17.3			52.1			61.3
Transportation	26.8			25.6			64.7			59.7
Total throughput	40.2			42.9			116.8			121.0
Degree days (% of normal)*
Montana-Dakota	77		%	120		%	77		%	112		%
Cascade	94		%	118		%	99		%	107		%
Intermountain	97		%	141		%	94		%	113		%
* Degree days are a measure of the daily temperature-related demand for energy for heating.

The combined utility businesses reported a loss of $2.0 million in the second quarter of 2012, compared to earnings of $6.7 million for the same period in 2011. This decrease reflects $4.4 million related to lower natural gas retail sales volumes resulting from significantly warmer weather than last year. Other factors include higher operation and maintenance expenses, largely increased contract services and higher benefit-

related costs, as well as higher income taxes. These decreases were partially offset by higher electric retail sales volumes of 8 percent.

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

•

The EPA approved the South Dakota Regional Haze Program which requires the Big Stone Station to install and operate a best available retrofit technology (BART) air quality control system to reduce emissions of particulate matter, sulfur dioxide and nitrogen oxides. The North Dakota Public Service Commission issued an order approving advance determination of prudence for recovery of costs related to this system in electric rates charged to customers. The company's share of the cost is estimated at $125 million.

•

The NDPSC issued an order approving the advance determination of prudence and a Certificate of Public Convenience and Necessity on the construction of an 88-MW simple cycle natural gas turbine and associated facilities projected to be in service in 2015, with an estimated project cost of $85.6 million. The turbine will be located on currently owned property that is adjacent to the company's Heskett Generating Station near Mandan, North Dakota and is necessary to meet the capacity requirements of the company's integrated electric system customers. The capacity will be a partial replacement for third party contract capacity expiring in 2015.


•	The company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors with company and customer-owned pipeline facilities designed to serve existing facilities currently served by fuel oil or propane, and to serve new customers. The company is currently engaged on a 30-mile natural gas line project into the Hanford Nuclear Site in Washington.


•	Currently the company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho.


•	The company plans to invest approximately $75 million in 2012 to serve the growing electric and gas customer base associated with the Bakken oil development in western North Dakota and eastern Montana.


•	The company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of energy to major market areas.



Pipeline and Energy Services
	Three Months Ended							Six Months Ended
	June 30,							June 30,
	2012				2011			2012			2011
	(Dollars in millions)
Operating revenues	$	43.6			$	72.4		$	93.2		$	146.4
Operating expenses:
Purchased natural gas sold	8.5				33.9			24.6			68.0
Operation and maintenance	(1.4		)	*	18.6			15.6		*	36.2
Depreciation, depletion and amortization	6.8				6.4			13.1			12.8
Taxes, other than income	3.5				3.4			6.9			7.0
	17.4				62.3			60.2			124.0
Operating income	26.2				10.1			33.0			22.4
Earnings	$	15.8			$	4.8		$	18.6		$	11.7
Transportation volumes (MMdk)	36.8				25.8			68.8			53.1
Gathering volumes (MMdk)	11.6				16.9			25.8			34.4
Customer natural gas storage balance (MMdk):
Beginning of period	27.3				32.9			36.0			58.8
Net injection (withdrawal)	13.1				(1.2		)	4.4			(27.1		)
End of period	40.4				31.7			40.4			31.7
* Reflects a net benefit of $24.1 million ($15.0 million after tax) related to the natural gas gathering operations litigation.

This segment reported second quarter earnings of $15.8 million, compared to earnings of $4.8 million for the same period in 2011. The earnings increase includes a net benefit of $15.0 million after tax related to the natural gas gathering operations litigation. This increase was partially offset by lower gathering volumes, as well as an impairment of certain natural gas gathering assets of $1.7 million (after tax).

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


•	The company and Calumet Refining, LLC are exploring the feasibility of jointly building and operating a 20,000 barrel per day diesel topping plant in southwestern North Dakota. The facility would process Bakken crude and market the diesel within the Bakken region. Site selection, permitting, crude oil procurement, marketing and engineering studies are currently underway.

•

In May, the company announced an agreement purchasing 50 percent undivided interest in Whiting Oil and Gas Corporation's natural gas and oil midstream assets near Belfield, N.D. in the Bakken area. The company paid $66 million at closing and will be responsible for 60 percent of certain future capital expenditures as specified in the agreement. The Belfield natural gas processing plant has an inlet processing capacity of 35 million cubic feet per day. The oil terminal is currently under construction, with completion expected in the third quarter of 2012.

•

The company expects average natural gas storage balances for the remainder of the year to be comparable to last year. The curtailment and/or divestment of certain natural gas properties and the deferral of certain gas development activity are expected to result in gathering volumes being lower in 2012 compared to last year. The decline is expected to be partially offset by higher transportation volumes related to growth projects placed in service in the Bakken area.

•

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.


•	In August the company expects to place in service approximately 13 miles of high pressure transmission pipeline from the Stateline processing facilities in northwestern North Dakota to deliver gas into the Northern Border Pipeline.

Construction



Construction Materials and Contracting
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012			2011
	(Dollars in millions)
Operating revenues	$	442.1	$	375.6	$	591.5		$	519.2
Operating expenses:
Operation and maintenance	396.7		334.2		553.7			481.1
Depreciation, depletion and amortization	19.8		21.2		39.6			42.6
Taxes, other than income	10.6		9.8		18.6			17.5
	427.1		365.2		611.9			541.2
Operating income (loss)	15.0		10.4		(20.4		)	(22.0		)
Earnings (loss)	$	7.8	$	5.0	$	(17.1	)	$	(16.4	)
Sales (000's):
Aggregates (tons)	6,481		6,479		8,974			9,306
Asphalt (tons)	1,761		1,842		1,861			2,007
Ready-mixed concrete (cubic yards)	837		698		1,305			1,095



Construction Services
	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(In millions)
Operating revenues	$	224.1	$	198.1	$	442.3	$	401.5
Operating expenses:
Operation and maintenance	198.6		178.3		386.6		363.2
Depreciation, depletion and amortization	2.8		2.8		5.5		5.8
Taxes, other than income	7.2		5.5		15.0		13.2
	208.6		186.6		407.1		382.2
Operating income	15.5		11.5		35.2		19.3
Earnings	$	8.7	$	6.1	$	20.1	$	10.8

The combined construction businesses reported second quarter earnings of $16.5 million, compared to earnings of $11.1 million a year ago. The earnings increase reflects higher equipment sales and rental margins and higher workloads and margins in the Central region at the services group, as well as higher construction margins at the materials group. Partially offsetting these increases were lower asphalt margins and volumes.

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

•

The construction materials work backlog as of June 30 was approximately $636 million, compared to approximately $649 million a year ago. The June 30 backlog at construction services was approximately $344 million, compared to approximately $364 million a year ago. The backlog includes a variety of projects such as highway paving projects, airports, bridge work, reclamation, harbor expansions, substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.


•	The company's backlog in the Bakken area of North Dakota is approximately $58 million.


•	Projected revenues included in the company's 2012 earnings guidance are in the range of

$1.4 billion to $1.5 billion for construction materials and $775 million to $875 million for construction services.


•	The company anticipates margins in 2012 to be higher compared to 2011.


•	The company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, substations, utility services, solar, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expansion into new markets.


•	As the country's 5^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.

Other



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012		2011			2012		2011
	(In millions)
Operating revenues	$	2.5	$	2.8		$	4.6	$	5.3
Operating expenses:
Operation and maintenance	1.5		1.9			2.9		4.9
Depreciation, depletion and amortization	.5		.4			1.0		.7
Taxes, other than income	.1		—			—		.1
	2.1		2.3			3.9		5.7
Operating income (loss)	.4		.5			.7		(.4		)
Income from continuing operations	.5		1.1			1.0		1.1
Income (loss) from discontinued operations, net of tax	5.1		(.1		)	5.0		.2
Earnings	$	5.6	$	1.0		$	6.0	$	1.3

Earnings were $5.6 million for the quarter, which reflects discontinued operations related to a net benefit largely resulting from estimated insurance recoveries associated with a construction contract at the domestic power production business, which was sold in 2007. For previous disclosure regarding this matter, refer to Note 17 of the company's most recent Form 10-Q filed with the Securities and Exchange Commission.

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 reflects an adjustment to exclude the reversal of an arbitration charge of $15.0 million after tax, or 8 cents per common share. 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 exploration and production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, which are subject to various external influences that cannot be controlled.


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


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

•

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


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


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


•	Actual quantities of recoverable oil and natural gas reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. There is a risk that changes in estimates of reserve quantities or other factors including downward movements in prices, could result in a future noncash write-down of the company's oil and natural gas properties.


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


•	Initiatives to reduce greenhouse gas emissions could adversely impact the company’s electric generation operations.


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


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


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


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


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


•	The company's operations may be negatively impacted by cyber attacks or acts of terrorism.


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


◦	Acquisition, disposal and impairments of assets or facilities.


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


◦	Changes in present or prospective generation.


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


◦	The availability of economic expansion or development opportunities.


◦	Population growth rates and demographic patterns.


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


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


◦	Changes in tax rates or policies.


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


◦	Unanticipated changes in operating expenses or capital expenditures.


◦	Labor negotiations or disputes.


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


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


◦	Changes in technology.


◦	Changes in legal or regulatory proceedings.


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


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


◦	Increases in employee and retiree benefit costs and funding requirements.

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



MDU Resources Group, Inc.
	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2012		2011			2012		2011
	(In millions, except per share amounts)
	(Unaudited)
Operating revenues	$	968.0	$	930.8		$	1,820.8	$	1,832.6
Operating expenses:
Fuel and purchased power	15.2		14.5			33.6		31.4
Purchased natural gas sold	58.4		101.6			243.9		346.2
Operation and maintenance	676.1		606.6			1,120.6		1,034.4
Depreciation, depletion and amortization	83.6		83.3			169.0		168.0
Taxes, other than income	43.0		42.5			90.9		92.2
	876.3		848.5			1,658.0		1,672.2
Operating income	91.7		82.3			162.8		160.4
Earnings from equity method investments	.4		.9			1.6		1.4
Other income	1.2		1.9			2.4		3.8
Interest expense	17.6		20.0			37.1		42.0
Income before income taxes	75.7		65.1			129.7		123.6
Income taxes	26.7		19.9			44.8		35.8
Income from continuing operations	49.0		45.2			84.9		87.8
Income (loss) from discontinued operations, net of tax	5.1		(.1		)	5.0		.2
Net income	54.1		45.1			89.9		88.0
Dividends declared on preferred stocks	.2		.2			.3		.3
Earnings on common stock	$	53.9	$	44.9		$	89.6	$	87.7

Earnings per common share – basic:
Earnings before discontinued operations	$	.26	$	.24		$	.45	$	.46
Discontinued operations, net of tax	.03		—			.02		—
Earnings per common share – basic	$	.29	$	.24		$	.47	$	.46
Earnings per common share – diluted:
Earnings before discontinued operations	$	.26	$	.24		$	.45	$	.46
Discontinued operations, net of tax	.03		—			.02		—
Earnings per common share – diluted	$	.29	$	.24		$	.47	$	.46
Dividends declared per common share	$	.1675	$	.1625		$	.3350	$	.3250
Weighted average common shares outstanding – basic	188.8		188.8			188.8		188.7
Weighted average common shares outstanding – diluted	189.1		189.0			189.1		188.9

Note: Three months and six months ended June 30, 2012 reflect the effects of a net benefit of $24.1 million ($15.0 million after tax or 8 cents per share) related to the natural gas gathering operations litigation.



	Six Months Ended
	June 30,
	2012			2011
	(Unaudited)

Other Financial Data
Book value per common share	$	14.86		$	14.36
Market price per common share	$	21.61		$	22.50
Dividend yield (indicated annual rate)	3.1		%	2.9		%
Price/earnings ratio*	19.1x			17.9x
Market value as a percent of book value	145.4		%	156.7		%
Return on average common equity*	7.7		%	8.9		%
Total assets**	$	6.9		$	6.3
Total equity**	$	2.8		$	2.7
Total debt **	$	1.7		$	1.4
Capitalization ratios:
Total equity	63		%	66		%
Total debt	37			34
	100		%	100		%

* Represents 12 months ended

** In billions

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MDU RESOURCES GROUP INC Reports