MDU RESOURCES GROUP INC - FORM 8-K - EX-99 - MDU-12-31-2014 EARNINGS RELEASE

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8-K - MDU-12-31-2014 EARNINGS RELEASE - MDU RESOURCES GROUP INC	mduye20148k.htm

MDU Resources Reports Higher 2014 Earnings, Initiates Guidance for 2015


•	Construction services reports second consecutive year of record earnings.


•	Construction materials has higher earnings.


•	Utility plans record capital investment program over next five years.


•	Pipeline and energy services earnings improve substantially; diesel refinery to begin commercial production in second quarter.


•	Company has substantial investment opportunities, plans for record capital expenditures of $3.9 billion over next five years.

BISMARCK, N.D. - Feb. 2, 2015 - MDU Resources Group, Inc. (NYSE:MDU) today reported 2014 consolidated GAAP earnings of $297.5 million, or $1.55 per share, compared to $278.2 million, or $1.47 per share, in 2013. Consolidated GAAP earnings in the fourth quarter were $84.1 million, or 43 cents per share, compared to earnings of $91.3 million, or 48 cents per share, in 2013.

"We had solid performance from our business units in 2014, which is a testament to our management team and employees' ability to execute even in light of challenges presented by lower commodity prices and unfavorable weather impacts," said David L. Goodin, president and CEO of MDU Resources Group. "As we look forward, we are focused on execution of our business plans and investment opportunities at our utility, pipeline and energy services and construction operations, while also determining the appropriate timing of when to begin the marketing of our exploration and production business."

Because of the company’s strategic decision to market the exploration and production business, in this release adjusted earnings and adjusted earnings guidance are defined as results from its utility, pipeline and energy services and construction businesses. Earnings are adjusted for certain items and exclude results for its exploration and production business. GAAP earnings and GAAP earnings guidance are all-in.

For 2014, consolidated adjusted earnings were $206.0 million, or $1.07 per share, compared to $191.5 million, or $1.01 per share in 2013. Consolidated adjusted earnings in the fourth quarter were $67.9 million, or 35 cents per share compared to $66.1 million, or 35 cents per share in the fourth quarter of 2013.

Consolidated adjusted earnings is a non-GAAP measure. For an explanation of non-GAAP earnings adjustments, see the Reconciliation of GAAP to Adjusted Earnings and the Use of Non-GAAP Financial Measures sections in this press release.

"With our commitment to invest approximately $3.9 billion in capital projects over the next five years and our strategic decision to market our exploration and production business at the appropriate time in the future, I am confident we are well positioned to produce significant long-term value for shareholders with a lower overall business risk profile," Goodin said.

Business Unit Results

The construction services business reported earnings of $54.5 million, a second consecutive year of record earnings. The construction materials and contracting business also had higher results reporting earnings of $51.5 million on a GAAP basis. Adjusted earnings at this business net of a multiemployer pension plan withdrawal liability recorded in the fourth quarter were $59.9 million. On this basis, earnings in the fourth quarter of $17.7 million were the highest ever for the business in the fourth quarter, which followed a record third quarter. Their combined adjusted earnings were at the highest level since 2007 and continue a trend of four consecutive years of stronger combined earnings year-over-year.

The utility business reported earnings of $67.2 million. The electric utility increased earnings 5 percent as a result of a 4 percent increase in electric retail sales, as well as rate recovery for environmental upgrades. Natural gas earnings declined reflecting a $4.3 million effect from warmer weather as well as higher operation and maintenance expense. Although a prolonged period of lower commodity prices may slow growth in the future, customer growth in the Bakken was still 5 percent for electric and 3 percent for natural gas in 2014. The combined group experienced customer growth of about 2 percent in 2014.

The utility group has a record five-year capital program that is projected to grow its rate base approximately 11 percent annually over the next five years on a compound basis. It includes investments in new electric generation, transmission and distribution to serve growing customer demand. The electric utility recently signed an agreement to purchase a 107.5-MW wind farm that will be built this year in North Dakota. The utility also expects to complete a $360 million upgrade to the Big Stone generating plant this year of which the company's share is $90 million. The utility group is also working on a 345-kilovolt transmission line for the Midcontinent Independent System Operator and has plans to construct 19 MW of natural gas fired generation near its Lewis & Clark station in Sidney, Montana scheduled to be online later this fall.

The pipeline and energy services business increased earnings substantially to $22.6 million with strong results from its 50 percent ownership of the Pronghorn natural gas and oil gathering and processing facility and higher transportation rates primarily related to the partial year effects of a rate case settlement. Total transportation volumes reached a record level, increasing 31 percent.

As announced last month, the Dakota Prairie Refining facility is expected to begin commercial production of diesel fuel and other products in the second quarter of this year. EBITDA for the first full year of operation is projected to be in the range of $60 million to $80 million, to be shared equally with Calumet. Demand for diesel in the region continues to be well above local supply levels. In light of construction delays and higher revised construction costs, return expectations continue to be solid for the project. The company is evaluating constructing a second 20,000-barrel-per-day refinery.

The pipeline group also has a record capital program. The company has entered into an agreement to construct a pipeline to connect the third-party announced Demicks Lake natural gas processing plant in northwestern North Dakota to deliver natural gas into a new interconnect with the Northern Border Pipeline. Project costs are estimated in the $50 million to $60 million range. In addition, the pipeline group has continued with permitting and acquisition of easements on the $120 million Wind Ridge Pipeline project to provide 90 million cubic feet per day of natural gas to a fertilizer manufacturing plant to be built at Spiritwood, North Dakota. There is an opportunity to expand this pipeline’s capacity to serve other customers in eastern North Dakota.

Earnings at the exploration and production business, adjusted for the unrealized fair value changes from derivatives, were $82.1 million. GAAP earnings were $96.8 million. Oil production increased slightly in 2014, led by 25 percent production growth in the Paradox Basin and the purchase of Powder River Basin non-operated assets partially offset by the sale of some Bakken assets in North Dakota. Natural gas and natural gas liquids production decreased as a result of divestment of certain assets in the Green River Basin and South Texas.

In the fourth quarter, the exploration and production group successfully completed the Cane Creek Unit 28-3 well in the Paradox Basin. The well was slowly ramped up to about 600 barrels of oil per day utilizing an 11/64ths-inch choke at a flowing tubing pressure of approximately 2,600 psi. The production rate has been held relatively constant for the last three weeks. These early indications show this well to be a strong producer. Additionally, the company completed its first East Texas Cotton Valley horizontal well, the Poovey Mark Poovey 1H. Initial production rate for the well peaked at 11 MMCFD declining to recent rates of 9 MMCFD.

MDU Resources previously announced that it intends to market Fidelity Exploration & Production Company, but has delayed the process in light of the recent volatility in oil prices. The decision to market the business is the result of a comprehensive review whereby the company concluded that the capital required to develop Fidelity’s assets and grow production at a meaningful level would significantly limit the amount of capital available to grow the corporation’s other businesses.

The company updated its 2015 capital expenditures forecast to $692 million reflecting a shift of some capital to primarily 2016 considering recent volatility in oil prices and the delayed marketing of the exploration and production business. Specifically, capital expenditures associated with a potential second refinery and acquisition capital at the construction businesses have been shifted into 2016. The company also updated its 2015 capital expenditure forecast for the exploration and production business and expects to operate within estimated cash flows.

Initiating 2015 Guidance

The company has initiated 2015 adjusted earnings per share guidance in the range of $1.05 to $1.20. Adjusted earnings per share guidance includes results from its utility, pipeline and energy services and construction businesses and excludes results for its exploration and production business. GAAP earnings per share is expected to be in the range of 80 cents to 95 cents for 2015 excluding any potential ceiling test impairments. GAAP earnings and GAAP earnings guidance are all-in.

The company will host a webcast at 10 a.m. EST Tuesday, Feb. 3, to discuss 2014 earnings results and 2015 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 58359497.

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, construction materials and services, and exploration and production. 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.

Adjusted Earnings by Segment



Business Line	Fourth Quarter 2014 Adjusted Earnings		Fourth Quarter 2013 Adjusted Earnings		2014 Adjusted Earnings		2013 Adjusted Earnings
	(In millions)
Regulated
Electric and natural gas utilities	$	28.7	$	31.4	$	67.2	$	72.5
Pipeline and energy services	7.4		4.9		22.6		15.1
Construction materials and services	31.4		27.8		114.4		103.1
Other and eliminations	.4		2.0		1.8		.8
Adjusted earnings*	$	67.9	$	66.1	$	206.0	$	191.5
* Excludes exploration and production

Reconciliation of GAAP to Adjusted Earnings



	Fourth Quarter 2014 Earnings			Fourth Quarter 2013 Earnings			2014 Earnings			2013 Earnings
	(In millions, except per share amounts)
Earnings per share	$	.43		$	.48		$	1.55		$	1.47
Earnings on common stock	$	84.1		$	91.3		$	297.5		$	278.2
Adjustments net of tax:
Exploration and production earnings	(21.9		)	(23.7		)	(96.8		)	(94.5		)
Discontinued operations	(2.7		)	—			(3.1		)	.3
Multiemployer pension plan withdrawal liability	8.4			—			8.4			—
Natural gas gathering asset impairment	—			—			—			9.0
Net benefit related to natural gas gathering operations litigation	—			(1.5		)	—			(1.5		)
Adjusted earnings	$	67.9		$	66.1		$	206.0		$	191.5
Adjusted earnings per share	$	.35		$	.35		$	1.07		$	1.01

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

•

Adjusted earnings per share for 2015 are projected in the range of $1.05 to $1.20. Adjusted earnings excludes the effects of the exploration and production segment. GAAP earnings per share guidance for 2015 is in the range of 80 cents to 95 cents. GAAP guidance does not include any potential ceiling test impairments related to lower commodity prices. Given the current oil and natural gas pricing environment, the company believes it is likely it will have noncash ceiling test write-downs of its oil and natural gas properties in 2015. The quarterly ceiling test considers many factors including reserves, capital expenditure estimates and trailing-twelve-month average prices. Securities and Exchange Commission Defined Prices for each quarter in 2014 were as follows:



SEC Defined Prices for 12 months ended	NYMEX Oil Price (per Bbl)		Henry Hub Gas Price (per MMBtu)		Ventura Gas Price (per MMBtu)
Dec. 31, 2014	$	94.99	$	4.34	$	7.71
Sept. 30, 2014	$	99.08	$	4.24	$	7.60
June 30, 2014	$	100.27	$	4.10	$	7.47
March 31, 2014	$	98.46	$	3.99	$	7.33


•	The company's long-term compound annual growth goals on earnings per share from operations are in the range of 7 to 10 percent.


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


•	The company focuses on creating value through vertical integration between its business units.


•	Capital expenditures for 2014 and estimated capital expenditures for 2015 through 2019 are noted in the following table:



Capital Expenditures
Business Line	2014 Actual			2015 Estimated			2016 Estimated			2017 Estimated			2015 - 2019 Total Estimated
							(In millions)
Regulated
Electric	$	185		$	319		$	172		$	177		$	1,031
Natural gas distribution	121			159			191			158			751
Pipeline and energy services*	177			111			423			336			1,121
Construction
Construction materials and contracting	38			49			206			123			638
Construction services	27			24			82			72			344
Other	2			5			4			2			14
Exploration and production**	601			111			—			—			111
Net proceeds and other	(307		)	(86		)	(4		)	(7		)	(118		)
Total capital expenditures	$	844		$	692		$	1,074		$	861		$	3,892

* Capital expenditure projections include the company's proportionate share of Dakota Prairie Refining.
** Future exploration and production capital expenditures are dependent upon the timing of marketing and sale. Sale proceeds for the business are excluded from capital expenditure projections.

Regulated

Electric and Natural Gas Utilities



Electric
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(Dollars in millions, where applicable)
Operating revenues	$	70.2		$	67.3		$	277.9		$	257.3
Operating expenses:
Fuel and purchased power	22.5			23.8			89.3			83.5
Operation and maintenance	20.8			20.1			81.1			76.5
Depreciation, depletion and amortization	9.1			8.2			35.0			32.8
Taxes, other than income	2.7			1.7			11.1			10.2
	55.1			53.8			216.5			203.0
Operating income	15.1			13.5			61.4			54.3
Earnings	$	8.7		$	9.2		$	36.7		$	34.8
Retail sales (million kWh)	888.4			843.7			3,308.4			3,173.1
Average cost of fuel and purchased power per kWh	$	.024		$	.026		$	.025		$	.025

Natural Gas Distribution
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(Dollars in millions)
Operating revenues	$	305.5		$	315.2		$	922.0		$	851.9
Operating expenses:
Purchased natural gas sold	206.8			211.2			603.2			534.8
Operation and maintenance	38.4			37.4			150.2			142.3
Depreciation, depletion and amortization	14.2			12.8			54.7			50.0
Taxes, other than income	12.9			13.1			48.3			46.0
	272.3			274.5			856.4			773.1
Operating income	33.2			40.7			65.6			78.8
Earnings	$	20.0		$	22.2		$	30.5		$	37.7
Volumes (MMdk):
Sales	35.5			40.5			104.3			108.3
Transportation	39.8			44.0			145.9			149.5
Total throughput	75.3			84.5			250.2			257.8
Degree days (% of normal)*
Montana-Dakota/Great Plains	96		%	111		%	103		%	105		%
Cascade	86		%	109		%	89		%	98		%
Intermountain	93		%	110		%	95		%	110		%
* Degree days are a measure of the daily temperature-related demand for energy for heating.

The combined utility businesses reported earnings of $67.2 million, compared to $72.5 million in 2013. This decrease reflects warmer weather effects of $4.3 million and higher operation and maintenance expense, largely related to higher payroll and benefit-related costs, and higher depreciation, depletion and amortization expense due to increased plant additions. Also contributing to the decrease was the absence of the 2013 gain on the sale of Montana-Dakota's nonregulated appliance service and repair business. Partially offsetting these decreases were increased electric retail sales margins, primarily due to rate recovery on electric environmental upgrades, and increased electric sales volumes of 4 percent to all customer classes.

Fourth quarter combined utility earnings were $28.7 million, compared to $31.4 million in 2013. The decrease in earnings reflects lower natural gas retail sales volumes resulting from warmer weather than last year and higher depreciation, depletion and amortization expense. Partially offsetting these decreases were higher electric retail sales margins, primarily due to rate recovery on electric environmental upgrades and increased electric sales volumes of 5 percent to all customer classes.

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


•	Rate base growth is projected to be approximately 11 percent compounded annually over the next five years, including plans for an approximate $1.8 billion gross capital investment program with $478 million planned for 2015. Although a prolonged period of lower commodity prices may slow Bakken-area growth in the future, the company continues to see strong current growth.


•	Regulatory actions

◦

July 10 the North Dakota Public Service Commission approved recovery of $8.6 million annually effective July 15 to reflect actual costs incurred through February and projected costs through June 2015 for an environmental cost recovery rider related to costs resulting from the retrofit required to be installed at the Big Stone Station. The company's share of the cost for the installation is approximately $90 million and is expected to be complete in 2015. The commission had earlier approved advance determination of prudence for recovery of costs on the system.

◦

Aug. 11 the company filed an application with the Montana Public Service Commission for a natural gas rate increase of approximately $3.0 million annually, or 3.6 percent above current rates. The requested increase includes costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. An interim increase of $2.2 million annually, or 2.6 percent, was requested, subject to refund. A hearing is scheduled for March 25.


◦	Oct. 3 the company filed an application with the Wyoming Public Service Commission for a natural gas rate increase of approximately $788,000 annually, or 4.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. A hearing is scheduled for May 19.

◦

Nov. 14 the company filed an application with the NDPSC for approval to implement the rate adjustment associated with the electric generation resource recovery rider previously approved by the commission. The rider was established to recover costs associated with new generation such as the Heskett III 88-MW natural gas combustion turbine. The commission approved rate adjustments of $5.3 million annually which were implemented Jan. 9.

◦

Dec. 22 the company filed for advanced determination of prudence with the NDPSC on the Thunder Spirit Wind project. The company recently signed an agreement to purchase the project, which includes 43 wind turbines totaling 107.5 MW of electric generation at a cost of approximately $200 million with approximately $55 million already funded in 2014. The project is being developed by ALLETE Clean Energy with an expected completion in December 2015.


◦	The company has planned natural gas rate case filings in early 2015 for Oregon and North Dakota. The company expects to file electric rate cases in 2015 in Montana and South Dakota and a natural gas case in Washington.


•	Investments are being made in 2015 totaling approximately $60 million to serve the growing electric and natural gas customer base associated with the Bakken oil development where customer growth is higher than the national average. This reflects a slightly lower capital expenditure level compared to 2014 anticipating a tempering of economic activity due to recent lower oil prices.


•	The company is engaged in a 30-mile, approximately $60 million natural gas line project into the Hanford Nuclear Site in Washington.

•

The company, along with a partner, expects to build a 345-kV transmission line from Ellendale, North Dakota, to Big Stone City, South Dakota, about 160 miles. The company’s share of the cost is estimated at approximately $170 million. The project is a Midcontinent Independent System Operator multi-value project. A route application was filed in August 2013 with the state of South Dakota and in October 2013 with the state of North Dakota. A route permit was approved July 10 in North Dakota and Aug. 13 in South Dakota. The South Dakota route permit was appealed and a district court ruled in favor of the project. The district court decision has been appealed to the South Dakota Supreme Court. The company continues to expect the project to be complete in 2019.


•	The company is pursuing additional generation projects to meet projected capacity requirements, including 19 MW of natural gas generation at the Lewis & Clark Station slated for this year.


•	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 served by fuel oil or propane, and to serve new customers.


•	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.



Pipeline and Energy Services
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(Dollars in millions)
Operating revenues	$	51.8		$	53.5		$	215.9		$	202.1
Operating expenses:
Purchased natural gas sold	9.7			15.0			58.8			57.5
Operation and maintenance*	21.1			16.5			75.4			81.8
Depreciation, depletion and amortization	8.9			7.1			30.7			29.1
Taxes, other than income	3.4			3.3			13.4			13.6
	43.1			41.9			178.3			182.0
Operating income	8.7			11.6			37.6			20.1
Earnings*	$	7.4		$	6.4		$	22.6		$	7.6
Natural gas gathering asset impairment	—			—			—			9.0
Net benefit related to natural gas gathering operations litigation	—			(1.5		)	—			(1.5		)
Adjusted earnings	$	7.4		$	4.9		$	22.6		$	15.1
Transportation volumes (MMdk)	67.2			49.4			233.5			178.6
Natural gas gathering volumes (MMdk)	9.7			10.3			38.4			40.7
Customer natural gas storage balance (MMdk):
Beginning of period	18.4			38.1			26.7			43.7
Net injection (withdrawal)	(3.5		)	(11.4		)	(11.8		)	(17.0		)
End of period	14.9			26.7			14.9			26.7
* Reflects an impairment of gathering assets as well as a net benefit related to litigation, largely reflected in operation and maintenance expense.

Adjusted earnings at the pipeline and energy services segment were $22.6 million, compared to $15.1 million in 2013. The earnings increase reflects higher transportation rates, primarily resulting from a rate case settlement, as well as higher earnings from its interest in the Pronghorn natural gas and oil midstream assets, largely from higher volumes. Also contributing were favorable income tax changes, including higher income tax benefits. Partially offsetting these increases were lower storage services earnings and higher operation and maintenance expenses, largely payroll and benefits-related due primarily to start-up costs related to the Dakota Prairie Refinery. GAAP earnings were $22.6 million in 2014 compared to $7.6 million in 2013.

Fourth quarter adjusted earnings were $7.4 million, compared to $4.9 million in 2013. The earnings increase reflects higher transportation rates, primarily resulting from a rate case settlement, and higher transportation volumes. Also contributing were the earlier noted income tax changes. Partially offsetting these increases were lower storage services earnings and higher operation and maintenance expense. GAAP earnings were $7.4 million in fourth quarter 2014 compared to $6.4 million in the same period last year.

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

•

The company, in conjunction with Calumet Specialty Products Partners, L.P., formed Dakota Prairie Refining, LLC, to develop, build and operate a 20,000-barrel-per-day diesel topping plant in southwestern North Dakota. Construction began on the facility in late March 2013 with a projected in-service date in the second quarter this year. The refinery will process Bakken crude into diesel, which will be marketed within the Bakken region. Other by products, naphtha and atmospheric tower bottoms, are expected to be railed to other areas. The total project cost estimate is more than $400 million. EBITDA for the first full year of operation is projected to be in the range of $60 million to $80 million, to be shared equally with Calumet.


•	The company is evaluating the construction of a second 20,000-barrel-per-day topping plant to be located near Minot, North Dakota in the Bakken region. It is anticipated the economic evaluation of this project will continue through much of 2015.

•

The company continues work on acquiring right-of-way and easements as well as filing for applicable permits for its planned Wind Ridge Pipeline project, a 95-mile natural gas pipeline designed to deliver approximately 90 MMcf/day to an announced fertilizer plant near Spiritwood, North Dakota. The project cost is estimated to be approximately $120 million with an in-service date in 2017. There is an opportunity to expand this pipeline's capacity to serve other customers in eastern North Dakota.

•

The company has entered into an agreement with an anchor shipper to construct a pipeline to connect the Demicks Lake gas processing plant in northwestern North Dakota to deliver natural gas into a new interconnect with the Northern Border Pipeline. The company will be holding an open season to gauge additional interest in the project. Project costs are estimated in the $50 million to $60 million range.

•

The company continues to pursue new growth opportunities and expansion of existing facilities and services offered to customers. The company expects energy development to continue to grow long term within its geographic region, most notably in the Bakken area, where the company owns an extensive natural gas pipeline system. The company plans to invest $1.1 billion of capital related to ongoing energy and industrial development over the next five years.

Construction



Construction Materials and Contracting
	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2014		2013		2014		2013
	(Dollars in millions)
Operating revenues	$	407.5	$	400.2	$	1,765.3	$	1,712.1
Operating expenses:
Operation and maintenance	374.5		356.5		1,571.5		1,505.2
Depreciation, depletion and amortization	16.5		17.8		68.6		74.5
Taxes, other than income	8.1		8.1		38.8		38.8
	399.1		382.4		1,678.9		1,618.5
Operating income	8.4		17.8		86.4		93.6
Earnings	$	9.3	$	12.3	$	51.5	$	50.9
Multiemployer pension plan withdrawal liability	8.4		—		8.4		—
Adjusted Earnings	$	17.7	$	12.3	$	59.9	$	50.9
Sales (000's):
Aggregates (tons)	5,861		5,701		25,827		24,713
Asphalt (tons)	1,204		1,250		6,070		6,228
Ready-mixed concrete (cubic yards)	823		765		3,460		3,223



Construction Services
	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2014		2013		2014		2013
	(In millions)
Operating revenues	$	276.8	$	258.7	$	1,119.5	$	1,039.8
Operating expenses:
Operation and maintenance	251.5		227.5		990.7		910.7
Depreciation, depletion and amortization	3.3		3.0		12.9		11.9
Taxes, other than income	7.1		6.7		33.6		32.0
	261.9		237.2		1,037.2		954.6
Operating income	14.9		21.5		82.3		85.2
Earnings	$	13.7	$	15.5	$	54.5	$	52.2

Adjusted earnings for the combined construction businesses were $114.4 million for 2014, compared to $103.1 million in 2013. The earnings increase reflects increased asphalt margins, as well as higher ready-mixed concrete and aggregate volumes and margins at the materials group; and increased electrical supply sales and margins at the services group. Also contributing were favorable income tax changes, including the resolution of certain tax matters and higher income tax benefits. Partially offsetting these increases were higher selling, general and administrative expense, including higher payroll and benefit-related costs. GAAP earnings were $106.0 million in 2014, compared to $103.1 million in 2013.

Fourth quarter adjusted earnings for the combined construction businesses were $31.4 million, compared to $27.8 million in 2013. The earnings increase reflects higher construction margins at the materials group. Also contributing were favorable income tax changes, including the resolution of certain tax matters and higher income tax benefits. Partially offsetting these increases were higher selling, general and administrative expense, as well as lower margins in the Western Region, both at the services group. GAAP earnings were $23.0 million in fourth quarter 2014, compared to $27.8 million in the same period last year.

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

•

The construction materials approximate work backlog as of Dec. 31 was $438 million, compared to $456 million a year ago. Private work represents 11 percent of construction backlog and public work represents 89 percent of backlog. The Dec. 31 approximate backlog at construction services was $305 million, compared to $459 million a year ago. The backlogs include a variety of projects such as highway grading, paving and underground projects, airports, bridge work, subdivisions, substation and line construction, solar and other commercial, institutional and industrial projects including petrochemical work.


•	Projected revenues included in the company's 2015 earnings guidance are in the range of $1.7 billion to $1.9 billion for construction materials and $1.1 billion to $1.3 billion for construction services.


•	The company anticipates margins in 2015 to be in line with 2014 margins.


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


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

Exploration and Production



	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(Dollars in millions, where applicable)
Operating revenues:
Oil	$	62.7		$	104.7		$	409.9		$	431.9
Natural gas liquids	2.7			7.9			22.0			29.2
Natural gas	15.4			18.4			83.8			81.0
Realized commodity derivatives gain	27.3			1.2			8.5			.2
Unrealized commodity derivatives gain (loss)	6.6			(.9		)	23.4			(6.3		)
	114.7			131.3			547.6			536.0
Operating expenses:
Operation and maintenance:
Lease operating costs	18.2			18.8			88.2			82.2
Gathering and transportation	4.0			3.3			12.5			15.4
Other	9.2			10.0			43.3			42.9
Depreciation, depletion and amortization	42.8			48.6			198.1			186.4
Taxes, other than income:
Production and property taxes	7.3			9.5			46.1			46.6
Other	.3			.2			1.1			1.1
	81.8			90.4			389.3			374.6
Operating income	32.9			40.9			158.3			161.4
Earnings*	$	21.9		$	23.7		$	96.8		$	94.5
* Includes unrealized commodity derivatives (gain) loss (after tax)	(4.1		)	.5			(14.7		)	3.9
Production:
Oil (MBbls)	1,022			1,244			4,919			4,815
Natural gas liquids (MBbls)	108			193			609			781
Natural gas (MMcf)	4,453			7,006			20,822			28,008
Total production (MBOE)	1,872			2,605			8,998			10,264
Average realized prices (excluding realized and unrealized commodity derivatives gain/loss):
Oil (per barrel)	$	61.37		$	84.14		$	83.33		$	89.70
Natural gas liquids (per barrel)	$	24.54		$	40.88		$	36.06		$	37.39
Natural gas (per Mcf)	$	3.45		$	2.63		$	4.02		$	2.89
Average realized prices (including realized commodity derivatives gain/loss):
Oil (per barrel)	$	87.70		$	84.23		$	85.96		$	89.35
Natural gas liquids (per barrel)	$	24.54		$	40.88		$	36.06		$	37.39
Natural gas (per Mcf)	$	3.54		$	2.78		$	3.81		$	2.96
Average depreciation, depletion and amortization rate, per BOE	$	21.85		$	17.90		$	21.17		$	17.41
Production costs, including taxes, per BOE:
Lease operating costs	$	9.74		$	7.21		$	9.80		$	8.01
Gathering and transportation	2.13			1.26			1.38			1.50
Production and property taxes	3.90			3.62			5.12			4.54
	$	15.77		$	12.09		$	16.30		$	14.05
Notes:
• Oil includes crude oil and condensate; natural gas liquids are reflected separately.
• Results are reported in barrel of oil equivalents based on a 6:1 ratio.
• Effective April 1, 2013, hedge accounting was discontinued for commodity derivative instruments, therefore, prospective changes in fair value are recorded in the income statement.

Earnings at this segment were $96.8 million for 2014, compared to $94.5 million in 2013. This increase reflects higher average realized gas prices, an unrealized commodity derivatives gain in 2014, compared to a loss in 2013, and increased oil production. Also contributing were favorable income tax changes, including the resolution of certain tax matters and higher income tax benefits. Partially offsetting these increases were lower average realized oil prices, decreased gas production and higher depreciation, depletion and amortization expense.

Fourth quarter earnings at this segment were $21.9 million, compared to $23.7 million in 2013. Earnings reflect higher commodity derivatives adjustments, lower depreciation, depletion and amortization expense and higher average realized gas prices. Also contributing were favorable income tax changes, including the resolution of certain tax matters and higher income tax benefits. Offsetting these increases were lower average realized oil prices and natural gas liquids prices and decreased oil, natural gas and natural gas liquids production, primarily due to divestments.

The company's oil additions in 2014 were 15.1 million barrels, a 307 percent replacement of oil production. Natural gas liquids additions were 3.634 million barrels, or 597 percent of natural gas liquids production. Natural gas additions were 72.1 billion cubic feet, or 346 percent of natural gas production. Total additions were 30.8 MMBOE, a 342 percent reserve replacement ratio without revisions. For 2014, the company had net positive revisions of 4.266 MMBOE. The company sold approximately 14.796 MMBOE of reserves for $246.6 million. Year-end 2014 reserves totaled 91.940 MMBOE. The total net present value of the company's reserves increased to $1.429 billion compared to $1.335 billion in 2013.

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


•	The company intends to market its exploration and production company in the future and although an actual sale date is unknown, for forecasting purposes the company is assuming a sale transaction after 2015.


•	During 2015, the company plans to continue to focus on maximizing the value of the company to ultimately market it for sale including focusing on lowering its cost structure beyond the 25 percent general and administrative cost reduction already in place.

•

The company expects to spend approximately $111 million in gross capital expenditures in 2015 operating within projected cash flows. Plans are to minimize investments in the first half of the year to allow service costs to better align with the lower commodity price environment. The company currently has no rigs drilling on its operated properties and anticipates commencing drilling in the second half of the year.


•	Key activities for 2015 include:


◦	Commissioning and start-up of the gas gathering and processing facilities in the Paradox in addition to new wells and existing well recompletes.


◦	Completion of a backlog of wells in the non-operated Powder River Basin.


◦	Drilling and completing additional horizontal wells in East Texas.


◦	Completion of 2014 activity carryover in the Bakken.


•	Well updates:


◦	The CCU 28-3 well (100 percent working interest) was completed in mid-December and was slowly ramped up to about 600 BOPD utilizing an 11/64ths-inch choke and a flowing tubing pressure of approximately 2,600 psi. The production rate has been held relatively constant for the last three weeks.


◦	The company completed the Poovey Mark Poovey 1H well (100 percent working interest), its first East Texas Cotton Valley horizontal well. Initial production rate for the well peaked at 11 MMCFD declining to recent rates of 9 MMCFD.

•

The company is projecting a 2015 net loss of approximately $40 million to $50 million excluding any potential ceiling test impairments. Annual oil production is expected to decline approximately 22 percent in 2015 primarily due to 2014 divestments in the Bakken and limited oil related investments in 2015. Annual natural gas and natural gas liquids volumes are estimated to decrease 10 percent and 20 percent respectively in 2015 primarily the result of 2014 asset divestments in South Texas. The December 2015 oil production rate is estimated to decrease 14 percent compared to December 2014, while natural gas and natural gas liquids rates are estimated to increase 4 percent and 23 percent respectively. The company is assuming average NYMEX index prices for 2015 of $50 per barrel of crude oil, $3.00 per Mcf of natural gas and $24 per barrel of natural gas liquids.


•	Derivatives in place as of Feb. 2 include:


◦	For January through March 2015, 3,000 BOPD at a weighted average price of $98.00.


◦	For January through March 2015, 15,000 MMBtu of natural gas per day at a weighted average price of $4.39.


◦	For 2015, 10,000 MMBtu of natural gas per day at a weighted average price of $4.28.

Other



	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2014		2013			2014		2013
	(In millions)
Operating revenues	$	2.0	$	2.8		$	9.4	$	9.6
Operating expenses:
Operation and maintenance	.2		(.5		)	1.3		.8
Depreciation, depletion and amortization	.6		.5			2.2		2.1
Taxes, other than income	.1		—			.2		.1
	.9		—			3.7		3.0
Operating income	1.1		2.8			5.7		6.6
Income from continuing operations	3.3		3.0			7.5		5.1
Income (loss) from discontinued operations, net of tax	2.7		—			3.1		(.3		)
Earnings	$	6.0	$	3.0		$	10.6	$	4.8

Earnings were $10.6 million in 2014, compared to $4.8 million in 2013. The earnings increase resulted from favorable income taxes changes at both continuing and discontinued operations, including the resolution of certain tax matters and higher income tax benefits.

Fourth quarter earnings were $6.0 million, compared to $3.0 million in 2013. The earnings increase resulted from favorable income taxes changes at both continuing and discontinued operations, including the resolution of certain tax matters and higher income tax benefits.

Use of Non-GAAP Financial Measures

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:

Three Months Ended December 31, 2014 and 2013:


•	Exploration and production earnings of $21.9 million and $23.7 million in 2014 and 2013, respectively.


•	A multiemployer pension plan withdrawal liability of $8.4 million after tax in 2014.


•	A net benefit related to natural gas gathering operations litigation of $1.5 million after tax in 2013.

Twelve Months Ended December 31, 2014 and 2013:


•	Exploration and production earnings of $96.8 million and $94.5 million in 2014 and 2013, respectively.


•	A multiemployer pension plan withdrawal liability of $8.4 million after tax in 2014.


•	A net benefit related to natural gas gathering operations litigation of $1.5 million after tax in 2013.


•	Natural gas gathering asset impairment of $9.0 million after tax in 2013.

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 CEO 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, that are subject to various external influences that cannot be controlled.

•

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


•	The regulatory approval, permitting, construction, startup and/or operation of power generation facilities and Dakota Prairie Refinery may involve unanticipated events 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.


•	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 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, 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.


•	While the company plans to market and sell its exploration and production business, there is no assurance that it will be successful.


•	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						Twelve Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
	(In millions, except per share amounts)
	(Unaudited)
Operating revenues	$	1,163.2		$	1,184.4		$	4,670.6		$	4,462.4
Operating expenses:
Fuel and purchased power	22.5			23.8			89.3			83.5
Purchased natural gas sold	193.0			199.8			570.0			505.1
Operation and maintenance	701.0			673.1			2,929.1			2,805.7
Depreciation, depletion and amortization	95.2			98.0			401.4			386.8
Taxes, other than income	41.9			42.6			192.6			188.4
	1,053.6			1,037.3			4,182.4			3,969.5
Operating income	109.6			147.1			488.2			492.9
Earnings (loss) from equity method investments	.3			.2			—			(.1		)
Other income	2.4			1.8			10.0			6.8
Interest expense	22.1			20.6			87.0			84.0
Income before income taxes	90.2			128.5			411.2			415.6
Income taxes	10.1			37.2			120.0			136.7
Income from continuing operations	80.1			91.3			291.2			278.9
Income (loss) from discontinued operations, net of tax	2.7			—			3.1			(.3		)
Net income	82.8			91.3			294.3			278.6
Net loss attributable to noncontrolling interest	(1.5		)	(.2		)	(3.9		)	(.3		)
Dividends declared on preferred stocks	.2			.2			.7			.7
Earnings on common stock	$	84.1		$	91.3		$	297.5		$	278.2

Earnings per common share – basic:
Earnings before discontinued operations	$	.42		$	.48		$	1.53		$	1.47
Discontinued operations, net of tax	.01			—			.02			—
Earnings per common share – basic	$	.43		$	.48		$	1.55		$	1.47
Earnings per common share – diluted:
Earnings before discontinued operations	$	.42		$	.48		$	1.53		$	1.47
Discontinued operations, net of tax	.01			—			.02			—
Earnings per common share – diluted	$	.43		$	.48		$	1.55		$	1.47
Dividends declared per common share	$	.1825		$	.1775		$	.7150		$	.6950
Weighted average common shares outstanding – basic	194.1			188.9			192.5			188.9
Weighted average common shares outstanding – diluted	194.2			189.8			192.6			189.7



	December 31,
	2014			2013
	(Unaudited)

Other Financial Data
Book value per common share	$	16.66		$	15.01
Market price per common share	$	23.50		$	30.55
Dividend yield (indicated annual rate)	3.1		%	2.3		%
Price/earnings ratio (12 months ended)	15.2x			20.8		x
Market value as a percent of book value	141.1		%	203.5		%
Net operating cash flow (12 months ended)*	$	616		$	742
Total assets*	$	7,810		$	7,061
Total equity*	$	3,250		$	2,856
Total debt *	$	2,095		$	1,866
Capitalization ratios: **
Total equity	60.8		%	60.5		%
Total debt	39.2			39.5
	100.0		%	100.0		%

* In millions

** Includes noncontrolling interest

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MDU RESOURCES GROUP INC Reports