MDU RESOURCES GROUP INC - FORM 8-K - EX-99 - MDU RESOURCES PRESS RELEASE

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8-K - 8-K - MDU RESOURCES GROUP INC	mduye20138k.htm

MDU Resources Reports Higher 2013 Earnings, Initiates Guidance for 2014 and

Acquires Additional Paradox Basin Acreage


•	Construction services business reports record earnings with 36 percent increase


•	Construction materials business increases earnings by 57 percent


•	Utility natural gas sales increase 15 percent; electric retail sales grow 6 percent


•	Oil production achieves target with 30 percent increase; Paradox acreage position expanded


•	Open season launched for 375-mile proposed natural gas pipeline to move Bakken production


•	Initial earnings guidance for 2014 of $1.45 to $1.60 per share

BISMARCK, N.D. - Feb. 3, 2014 - MDU Resources Group, Inc. (NYSE:MDU) today reported 2013 consolidated adjusted earnings of $289.9 million, or $1.53 per share, compared to $218.9 million, or $1.16 per share in 2012. Consolidated GAAP earnings were $278.2 million, or $1.47 per share, compared to a loss of $1.4 million, or 1 cent per share, in 2012. 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 later in this press release.

The company reported consolidated adjusted earnings of $90.3 million, or 48 cents per share, in the fourth quarter of 2013 compared to $76.2 million, or 40 cents per share in the fourth quarter of 2012. Consolidated GAAP earnings were $91.3 million, or 48 cents per share, compared to a loss of $61.2 million, or 32 cents per share, in 2012.

“Adjusted earnings grew 32 percent for the year to the highest level since 2008 and shareholders experienced a total annual return of 48 percent in 2013, so this has been a very successful year,” said David L. Goodin, president and CEO of MDU Resources. “All of our businesses are operating exceptionally well. Our focus on substantial capital investment to grow our businesses is having an impact and with the added investments planned for this year, we expect to continue the momentum. We also successfully executed on more than $100 million in sales of non-strategic assets in 2013 and plan to maintain our focus on the efficient use of capital.”

The company’s exploration and production business achieved its growth target for oil production with a 30 percent increase, despite bitterly cold December temperatures that impacted operations across North Dakota’s oil fields. Over the past two years, Fidelity Exploration & Production Company’s oil production has increased 77 percent. Nearly 60 percent of Fidelity’s 4.8 million net barrels in 2013

came from the Bakken. Production also grew 221 percent in the prolific Paradox basin in Utah, where two back-to-back high-producing wells have highlighted the potential of this developing play.

A major portion of Fidelity’s $440 million 2014 drilling program will again be targeted at further development in the Bakken and Paradox areas. Two rigs are working in each of the plays. In addition, Fidelity recently acquired an additional 35,000 acres in the Paradox basin, bringing the acreage total there to approximately 130,000 net acres of leaseholds. The new acreage is on trend with our current Paradox acreage position and the geology is similar. The company continues to have an option to earn an additional 20,000 acres in the play.

The utility business reported earnings of $72.5 million, a 21 percent increase over 2012. Colder than normal temperatures at the beginning and end of 2013 helped push natural gas sales up 15 percent. The company also benefited from customer growth above the industry norm, surpassing the 1 million customer mark. To ensure the company can safely and reliably serve customer and load growth, the utility has been investing record amounts in its capital expenditure program. The 2014 plan of $300 million will set another record; approximately 25 percent of which will be targeted in the Bakken region, where the company experienced 6 percent electric and 4 percent natural gas customer growth last year. Construction of the utility’s $77 million 88-megawatt natural gas turbine is on schedule with operation expected to begin in the third quarter.

Adjusted earnings at the pipeline and energy services business for 2013 were higher, driven primarily by its interest in the Pronghorn natural gas and oil midstream assets which saw higher volumes.

WBI Energy expects to complete a new 15-mile pipeline by this summer, serving yet another new processing facility that is under construction in North Dakota. Construction of Dakota Prairie Refining, which WBI Energy is building with a partner, is on schedule with approximately 40 percent complete and is expected to be on line at the end of this year. The diesel topping plant will have the capacity to refine 20,000 barrels per day of Bakken crude oil. Total project costs have been revised upward to $350 million.

WBI Energy also recently launched an open season on a proposed approximately $650 million, 375-mile pipeline to be built across northern North Dakota to provide takeaway capacity for natural gas that is associated with Bakken oil production. The pipeline would have an initial capacity of 400 million cubic feet per day and would provide more transportation capacity for natural gas captured through industry's efforts to reduce flaring.

The construction services business had record earnings of $52.2 million which, when combined with the construction materials business’ six-year high of $50.9 million, pushed their combined earnings to their highest level since 2007, an increase of about 46 percent over 2012. The combined construction business backlog at year-end was approximately $915 million, $184 million higher than a year ago.

“2013 clearly was a very strong year for MDU Resources and as we look forward, we are confident that we are positioned to build on the momentum for growing the company with a record $4.4 billion of capital investment planned over the next five years,” Goodin said.

The company is initiating adjusted earnings guidance for 2014 in the range of $1.45 to $1.60 per share.

The company will host a webcast at 10 a.m. EST Tuesday, Feb. 4, to discuss 2013 earnings results and 2014 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 29265471.

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. 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 2013 Adjusted Earnings		Fourth Quarter 2012 Adjusted Earnings		2013 Adjusted Earnings		2012 Adjusted Earnings
	(In millions)
Exploration and production	$	24.2	$	25.7	$	98.4	$	70.0
Regulated
Electric and natural gas utilities	31.4		26.7		72.5		60.0
Pipeline and energy services	4.9		4.7		15.1		13.3
Construction materials and services	27.8		16.2		103.1		70.8
Other and eliminations	2.0		2.9		.8		4.8
Adjusted earnings	$	90.3	$	76.2	$	289.9	$	218.9

Reconciliation of GAAP to Adjusted Earnings



	Fourth Quarter 2013 Earnings			Fourth Quarter 2012 Earnings			2013 Earnings			2012 Earnings
	(In millions, except per share amounts)
Earnings (loss) on common stock	$	91.3		$	(61.2	)	$	278.2		$	(1.4	)
Adjustments net of tax:
Discontinued operations	—			(8.7		)	.3			(13.6		)
Unrealized commodity derivatives loss	.5			.2			3.9			.4
Natural gas gathering asset impairment	—			—			9.0			1.7
Net benefit related to natural gas gathering operations litigation	(1.5		)	—			(1.5		)	(15.0		)
Write-downs of oil and natural gas properties	—			145.9			—			246.8
Adjusted earnings	$	90.3		$	76.2		$	289.9		$	218.9
Adjusted earnings per share	$	.48		$	.40		$	1.53		$	1.16

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


•	Adjusted earnings per share for 2014 are projected in the range of $1.45 to $1.60. GAAP earnings guidance for 2014 is in the same range. Unrealized commodity derivatives fair values can fluctuate causing actual GAAP earnings to vary accordingly.


•	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. For example, the pipeline and energy services business' partially owned diesel topping plant under construction in the Bakken region has the construction materials and services business involved in constructing the facility, the exploration and production business supplying production, either directly or in kind, to the plant, the pipeline transporting natural gas to the plant, and the utility supplying electricity.


•	Capital expenditures for 2013 and estimated capital expenditures for 2014 through 2018 are noted in the following table.



Business Line	Capital Expenditures 2013 Actual			Capital Expenditures 2014 Estimated*			Capital Expenditures 2014 - 2018 Total Estimated*
	(In millions)
Exploration and production	$	391		$	441		$	2,381
Regulated
Electric	169			161			633
Natural gas distribution	101			141			667
Pipeline and energy services**	127			162			429
Construction
Construction materials and contracting	35			38			262
Construction services	15			22			82
Other	2			1			9
Net proceeds and other	(112		)	(7		)	(32		)
Total capital expenditures	$	728		$	959		$	4,431

* Capital expenditures for potential acquisitions of businesses would be incremental to these estimates.
** Capital expenditure projections include the company's proportionate share of Dakota Prairie Refining and exclude the proposed 375-mile pipeline project.

Exploration and Production



	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(Dollars in millions, where applicable)
Operating revenues:
Oil	$	104.7		$	96.1		$	431.9		$	313.4
Natural gas liquids	7.9			8.4			29.2			33.0
Natural gas	18.4			21.1			81.0			69.2
Realized commodity derivatives gain	1.2			9.0			.2			33.6
Unrealized commodity derivatives loss	(.9		)	(.2		)	(6.3		)	(.6		)
	131.3			134.4			536.0			448.6
Operating expenses:
Operation and maintenance:
Lease operating costs	18.8			19.6			82.2			77.7
Gathering and transportation	3.3			4.6			15.4			17.4
Other	10.0			8.6			42.9			37.0
Depreciation, depletion and amortization	48.6			48.0			186.4			160.7
Taxes, other than income:
Production and property taxes	9.5			11.8			46.6			39.7
Other	.2			.2			1.1			1.0
Write-downs of oil and natural gas properties	—			231.7			—			391.8
	90.4			324.5			374.6			725.3
Operating income (loss)	40.9			(190.1		)	161.4			(276.7		)
Earnings (loss)	$	23.7		$	(120.4	)	$	94.5		$	(177.2	)
Unrealized commodity derivatives loss	.5			.2			3.9			.4
Write-downs of oil and natural gas properties	—			145.9			—			246.8
Adjusted Earnings	$	24.2		$	25.7		$	98.4		$	70.0
Production:
Oil (MBbls)	1,244			1,139			4,815			3,694
Natural gas liquids (MBbls)	193			218			781			828
Natural gas (MMcf)	7,006			7,538			28,008			33,214
Total production (MBOE)	2,605			2,614			10,264			10,058
Average realized prices (excluding realized and unrealized commodity derivatives gain/loss):
Oil (per barrel)	$	84.14		$	84.27		$	89.70		$	84.84
Natural gas liquids (per barrel)	$	40.88		$	38.39		$	37.39		$	39.81
Natural gas (per Mcf)	$	2.63		$	2.80		$	2.89		$	2.08
Average realized prices (including realized commodity derivatives gain/loss):
Oil (per barrel)	$	84.23		$	88.45		$	89.35		$	86.54
Natural gas liquids (per barrel)	$	40.88		$	38.39		$	37.39		$	39.81
Natural gas (per Mcf)	$	2.78		$	3.36		$	2.96		$	2.91
Average depreciation, depletion and amortization rate, per BOE	$	17.90		$	17.70		$	17.41		$	15.28
Production costs, including taxes, per BOE:
Lease operating costs	$	7.21		$	7.50		$	8.01		$	7.73
Gathering and transportation	1.26			1.76			1.50			1.73
Production and property taxes	3.62			4.53			4.54			3.94
	$	12.09		$	13.79		$	14.05		$	13.40
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.

Adjusted earnings at this segment were $98.4 million for 2013, compared to $70.0 million in 2012. This increase reflects 30 percent higher oil production, largely related to drilling activity in the Bakken and Paradox areas. Higher average realized natural gas and oil prices were largely offset by a reduction of a realized commodity derivatives gain. Partially offsetting the earnings increase were higher depreciation, depletion and amortization, decreased natural gas production of 16 percent, higher production taxes and higher general and administrative expense. GAAP earnings were $94.5 million in 2013 compared to a loss of $177.2 million in 2012.

Fourth quarter adjusted earnings at this segment were $24.2 million compared to $25.7 million in 2012. This decrease reflects a lower realized commodity derivatives gain, higher income taxes, higher general and administrative expense and 7 percent lower natural gas production. Partially offsetting the earnings decrease were increased oil production of 9 percent, largely related to drilling activity in the Paradox and Bakken areas, as well as lower production taxes. GAAP earnings were $23.7 million in fourth quarter 2013 compared to a loss of $120.4 million in the same period last year.

The company's oil additions in 2013 were 13.3 million barrels, a 277 percent replacement of oil production. Natural gas liquids additions were 1.3 million barrels, or 171 percent of natural gas liquids production. Natural gas additions were 26.4 billion cubic feet, or 94 percent of natural gas production. Total additions were 19.1 MMBOE, a 186 percent reserve replacement ratio without revisions. For 2013, the company had net negative revisions of 0.6 MMBOE. Consistent with the company's strategic direction, it sold approximately 8 MMBOE of low value reserves for $84 million. Reserve additions were essentially offset by asset sales and production with year-end 2013 reserves totaling 80.7 MMBOE. The total net present value of the company's reserves increased to $1.335 billion compared to $1.063 billion in 2012.

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


•	The company expects to spend approximately $440 million in capital expenditures in 2014.

•

For 2014, the company expects a 10 to 20 percent increase in oil production and a 5 to 10 percent increase in natural gas liquids production. Natural gas production is expected to decline 20 to 30 percent compared to a year ago primarily the result of the divestment of certain non-strategic natural gas-based properties in 2013. The vast majority of the capital program is focused on growing oil production considering current relative commodity prices. The company expects to return to some natural gas development when the commodity prices make it more profitable to do so.


•	The company has a total of four drilling rigs deployed on its acreage in the Bakken and Paradox areas, with two rigs operating in each area.


•	Bakken areas


◦	The company owns a total of approximately 125,000 net acres of leaseholds in Mountrail and Stark counties, N.D. and Richland County, Mont. The Middle Bakken and Three Forks formations are targeted in North Dakota and the Red River formation is targeted in Montana.


◦	Capital expenditures are expected to total approximately $130 million in 2014.


◦	Net oil production for the fourth quarter was approximately 7,900 BOPD which is down 5 percent from third quarter. This quarter-on-quarter drop in oil production was primarily driven by weather-related downtime in December as well as delay of a three-well pad completion.


◦	Alternative completion techniques, including increased stage count and cemented liners in the Middle Bakken (Mountrail County) and Three Forks (Mountrail and Stark counties) are being tested, with completion design changes to be finalized later in 2014.


•	Paradox Basin, Utah


◦	The company owns approximately 130,000 net acres of leaseholds including its recent acquisition of 35,000 net acres of leaseholds and has an option to earn another 20,000 acres. The company expects to further expand its acreage in the basin.


◦	Capital expenditures are expected to total approximately $170 million in 2014.


◦	Well costs have increased and now range from $10 million to $11 million per well driven by increased lateral lengths. With longer lateral lengths, estimated ultimate recoveries are expected to increase with the upper range now at 1.5 MMBO per well.


◦	Following nine months of flowing at a constant 1,500 BOPD gross, the Cane Creek Unit 12-1 well came off its plateau rate and for the past seven months has still been flowing at approximately 1,000 BOPD. Cumulative production is 600 MBO.


◦	Net oil production for fourth quarter was approximately 2,850 BOPD, up 89 percent from fourth quarter 2012 and 24 percent higher than third quarter 2013. Current production is approximately 3,000 BOPD.

◦

The CCU 7-1 well has just been completed and is in the initial flowback and production ramp up period. Flowing on a 5/64 choke, the well was producing 350 BOPD at more than 3,000 psi flowing pressure. The well will be brought to full production capability over the next month. The CCU 36-1 has been flowing consistently at an average rate of 930 BOPD gross since Oct. 11 with an average flowing pressure of approximately 3,400 psi.


◦	The company's understanding of this play and the quality of the play continues to improve. It is anticipated that this field will play a key role in the company's oil growth strategy.


•	Other opportunities


◦	The company has continued its focus on adding a third oil play and will announce any progress if and when definitive agreements have been signed.


•	Earnings guidance reflects estimated average NYMEX index prices for February through December in the range of $90 to $95 per barrel of crude oil, and $3.75 to $4.25 per Mcf of natural gas. Estimated prices for natural gas liquids are in the range of $35 to $45 per barrel.


•	Derivatives:


◦	For the first six months of 2014, the company has derivative instruments for 11,000 BOPD, and 5,000 BOPD for July through December, utilizing swaps with a weighted average price of $94.74. Covering full-year 2014, the company has derivative instruments for 40,000 MMBtu of natural gas per day utilizing swaps at a weighted average price of $4.10.


◦	For 2015, the company has a derivative instrument for 10,000 MMBtu of natural gas per day utilizing a swap at $4.28.


◦	The commodity derivative instruments that are in place as of Feb. 3 are summarized in the following chart:



Commodity	Type	Index	Period Outstanding	Forward Notional Volume (Bbl/MMBtu)	Price (Per Bbl/MMBtu)
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$95.15
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$95.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$90.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$91.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$92.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$93.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$98.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$99.00
Crude Oil	Swap	NYMEX	1/14 - 6/14	181,000	$100.07
Crude Oil	Swap	NYMEX	1/14 - 12/14	365,000	$94.05
Crude Oil	Swap	NYMEX	1/14 - 12/14	365,000	$95.00
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$94.25
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$95.00
Crude Oil	Swap	NYMEX	7/14 - 12/14	184,000	$95.25
Natural Gas	Swap	NYMEX	1/14 - 12/14	7,300,000	$4.13
Natural Gas	Swap	NYMEX	1/14 - 12/14	3,650,000	$4.05
Natural Gas	Swap	NYMEX	1/14 - 12/14	3,650,000	$4.10
Natural Gas	Swap	NYMEX	1/15 - 12/15	3,650,000	$4.28

Regulated

Electric and Natural Gas Utilities



Electric
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(Dollars in millions, where applicable)
Operating revenues	$	67.3		$	62.5		$	257.3		$	236.9
Operating expenses:
Fuel and purchased power	23.8			21.1			83.5			72.4
Operation and maintenance	20.1			18.6			76.5			71.8
Depreciation, depletion and amortization	8.2			8.4			32.8			32.5
Taxes, other than income	1.7			2.5			10.2			10.3
	53.8			50.6			203.0			187.0
Operating income	13.5			11.9			54.3			49.9
Earnings	$	9.2		$	7.6		$	34.8		$	30.6
Retail sales (million kWh)	843.7			806.7			3,173.1			2,996.5
Average cost of fuel and purchased power per kWh	$	.026		$	.025		$	.025		$	.023

Natural Gas Distribution
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(Dollars in millions)
Operating revenues	$	315.2		$	250.0		$	851.9		$	754.8
Operating expenses:
Purchased natural gas sold	211.2			157.3			534.8			457.4
Operation and maintenance	37.4			36.5			142.3			139.4
Depreciation, depletion and amortization	12.8			11.7			50.0			45.7
Taxes, other than income	13.1			11.5			46.0			44.7
	274.5			217.0			773.1			687.2
Operating income	40.7			33.0			78.8			67.6
Earnings	$	22.2		$	19.1		$	37.7		$	29.4
Volumes (MMdk):
Sales	40.5			33.7			108.3			93.8
Transportation	44.0			37.3			149.5			132.0
Total throughput	84.5			71.0			257.8			225.8
Degree days (% of normal)*
Montana-Dakota/Great Plains	111		%	99		%	105		%	84		%
Cascade	109		%	91		%	98		%	96		%
Intermountain	110		%	90		%	110		%	91		%
* Degree days are a measure of the daily temperature-related demand for energy for heating.

The combined utility businesses reported record earnings of $72.5 million, compared to $60.0 million in 2012. This increase reflects higher natural gas retail sales volumes resulting from colder weather than last year and higher electric retail sales margins, including the result of 6 percent higher volumes. The company added approximately 21,000 new customers in 2013. A gain on the sale of Montana-Dakota's nonregulated appliance service and repair business and decreased net interest expense also increased earnings. Partially offsetting this increase was higher operation and maintenance expense, largely related to higher payroll-related costs, offset in part by lower benefit-related costs; as well as higher depreciation, depletion and amortization expense.

Fourth quarter combined utility earnings were $31.4 million, compared to $26.7 million in 2012. The increase in earnings reflects higher natural gas retail sales volumes resulting from colder weather than last year and higher electric retail sales margins, largely the result of 5 percent higher volumes. Partially offsetting this increase was higher operation and maintenance expense, largely related to higher payroll-related costs, offset in part by lower benefit-related costs.

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


•	Rate base growth is projected to be approximately 9 percent compounded annually over the next five years, including plans for an approximate $1.3 billion capital investment program.


•	Regulatory actions

◦

The company filed an application Sept. 18 with the North Dakota Public Service Commission for a natural gas rate increase requesting a total of $6.8 million annually or approximately 6.4 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and a new customer billing system. An interim increase of $4.3 million annually, approximately 4.0 percent, went into effect for service rendered beginning Nov. 17. On Dec. 30, a settlement agreement was approved by the commission for an increase in the same amount as the interim increase. A hearing on the rate design portion of the application is scheduled for Feb. 5.


◦	The company filed an application June 14 for an advance determination of prudence with NDPSC to add pollution control equipment at the Lewis & Clark generating station projected to be completed in 2016 to comply with the Mercury and Air Toxics Standards rules. On Oct. 9, the commission issued an order approving the ADP.

◦

The company filed an application Feb. 11 with NDPSC for approval of an environmental cost recovery rider related to ongoing construction costs at the Big Stone Station for the installation of the best-available retrofit technology air-quality control system. The company's share of the cost for the installation is estimated at $100 million and is expected to be complete in 2015. On Dec. 18, the commission approved the company’s request for the environmental cost recovery rider with an effective date of Jan. 15. The commission had earlier approved advance determination of prudence for recovery of costs on the system.

◦

The company filed an application Dec. 21, 2012 with the South Dakota Public Utilities Commission for a natural gas rate increase requesting a total of $1.5 million annually or approximately 3.3 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and new customer billing system. The company implemented the full request July 22, subject to refund. On Nov. 5, the commission approved a settlement stipulation for an increase of $900,000 annually, or 2.0 percent, effective with service rendered Dec. 1.

◦

The company filed an application Sept. 26, 2012, with the Montana Public Service Commission for a natural gas rate increase requesting a total of $3.5 million annually or approximately 5.9 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and new customer billing system. The commission granted an interim increase of approximately $850,000 annually, effective April 15. On Dec. 12, the commission approved a stipulation for an increase of $1.5 million annually, or 2.6 percent, effective with service rendered Dec. 15.


◦	Effective Nov. 1, 2013, the Washington Utilities and Transportation Commission approved recovery of $1.0 million over a one-year period for qualifying pipeline replacement projects. The commission issued a policy statement dated Dec. 31, 2012, related to the accelerated replacement of natural gas pipeline facilities.

•

The company is constructing an 88-megawatt simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $77 million and a projected in-service date in third quarter 2014. It is located on owned property adjacent to the company's Heskett Generating Station near Mandan, N.D. The capacity is necessary to meet the requirements of the company's integrated electric system customers and will be a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from NDPSC.


•	Investments are being made in 2014 totaling approximately $70 million to serve the growing electric and natural gas customer base associated with the Bakken oil development where customer growth is substantially higher than the national average.

•

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 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-kilovolt transmission line from Ellendale, N.D., to Big Stone City, S.D., about 160 miles, at a total cost of approximately $360 million. The company's share would be one-half. The project is a Midcontinent Independent System Operator multi-value project. A route application was filed in August with the state of South Dakota, and in October with the state of North Dakota. The project is expected to be complete in 2019.


•	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,
	2013			2012			2013			2012
	(Dollars in millions)
Operating revenues	$	53.5		$	51.6		$	202.1		$	193.1
Operating expenses:
Purchased natural gas sold	15.0			15.1			57.5			50.5
Operation and maintenance*	16.5			17.3			81.8			52.2
Depreciation, depletion and amortization	7.1			7.3			29.1			27.7
Taxes, other than income	3.3			3.2			13.6			13.6
	41.9			42.9			182.0			144.0
Operating income	11.6			8.7			20.1			49.1
Earnings*	$	6.4		$	4.7		$	7.6		$	26.6
Natural gas gathering asset impairment	—			—			9.0			1.7
Net benefit related to natural gas gathering operations litigation	(1.5		)	—			(1.5		)	(15.0		)
Adjusted earnings	$	4.9		$	4.7		$	15.1		$	13.3
Transportation volumes (MMdk)	49.4			34.8			178.6			137.7
Natural gas gathering volumes (MMdk)	10.3			10.6			40.7			47.1
Customer natural gas storage balance (MMdk):
Beginning of period	38.1			49.2			43.7			36.0
Net injection (withdrawal)	(11.4		)	(5.5		)	(17.0		)	7.7
End of period	26.7			43.7			26.7			43.7
* Reflects impairments of gathering assets as well as net benefits related to litigation, largely reflected in operation and maintenance expense.

Adjusted earnings at the pipeline and energy services segment were $15.1 million, compared to $13.3 million in 2012. The company saw higher earnings from its interest in the Pronghorn natural gas and oil midstream assets, primarily from higher volumes. Also contributing were lower operation and maintenance expense, largely lower payroll-related, contract services and legal. Partially offsetting these increases were lower storage services revenue and lower natural gas gathering volumes. GAAP earnings were $7.6 million in 2013 compared to $26.6 million in 2012.

Fourth quarter adjusted earnings were $4.9 million, compared to $4.7 million in 2012. This earnings increase reflects higher earnings from its interest in the Pronghorn natural gas and oil midstream assets, primarily from higher volumes, as well as higher transportation volumes. Partially offsetting these increases were lower storage services revenue and higher operation and maintenance expense. GAAP earnings were $6.4 million in fourth quarter 2013 compared to $4.7 million in the same period last year.

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

•

In January, the company launched an open season to obtain capacity commitments on a proposed 375-mile natural gas pipeline from western North Dakota to northwestern Minnesota to transport natural gas to markets in eastern North Dakota, Minnesota, Wisconsin, Michigan and other Midwest markets. The pipeline is expected to provide access to additional markets via interconnections with pipelines owned by Great Lakes Gas Transmission, Viking Gas Transmission and potentially TransCanada, in northwestern Minnesota. An interconnection with the Alliance Pipeline system in eastern North Dakota also is possible. Initially the pipeline would transport approximately 400 MMcf per day of natural gas and could be expanded to more than 500 MMcf per day. The project investment is estimated to be approximately $650 million. Following the open season and receipt of adequate capacity commitments and necessary permits and regulatory approvals, construction on the new pipeline could begin in 2016 with completion expected in 2017.

•

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 and, when complete, it will process Bakken crude into diesel, which will be marketed within the Bakken region. Other by-products, naphtha and atmospheric tower bottoms, will be railed to other areas. The total project cost estimate has been revised to approximately $350 million, with a projected in-service date in late 2014. EBITDA for the first year of operation is projected to be in the range of $70 million to $90 million, to be shared equally with Calumet.

•

Oct. 31, WBI Energy Transmission filed a Section 4 rate case with the FERC, the first case it has filed in approximately 14 years. An increase in investments of $312 million and increased operating costs since 1999, combined with reduced storage and off-system volumes because of narrowed basis and seasonal price spreads that have resulted from shale gas developments in the United States, are the drivers for the requested rate increase of $28.9 million annually. The proposed effective date of the rates was Dec. 1; however the commission has exercised a five-month delay moving the implementation of rates to May 1.

•

The company is engaged in various natural gas pipeline projects to be constructed in 2014, including connections for the planned Garden Creek II natural gas processing plant in the Bakken, an expansion of its transmission system to increase capacity to the Black Hills, and a 24-mile pipeline and related processing facilities to transport Fidelity's Paradox basin natural gas production. The total cost for these projects is approximately $50 million.


•	The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region is expanding, most notably in the Bakken area, where the company owns an extensive natural gas pipeline system. Ongoing energy development is expected to continue to provide growth opportunities for this business.

Construction



Construction Materials and Contracting
	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(Dollars in millions)
Operating revenues	$	400.2	$	375.9	$	1,712.1	$	1,617.4
Operating expenses:
Operation and maintenance	356.5		339.2		1,505.2		1,442.5
Depreciation, depletion and amortization	17.8		19.6		74.5		79.5
Taxes, other than income	8.1		8.0		38.8		37.5
	382.4		366.8		1,618.5		1,559.5
Operating income	17.8		9.1		93.6		57.9
Earnings	$	12.3	$	7.7	$	50.9	$	32.4
Sales (000's):
Aggregates (tons)	5,701		5,302		24,713		23,285
Asphalt (tons)	1,250		1,114		6,228		5,988
Ready-mixed concrete (cubic yards)	765		747		3,223		3,157



Construction Services
	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
	(In millions)
Operating revenues	$	258.7	$	249.1	$	1,039.8	$	938.6
Operating expenses:
Operation and maintenance	227.5		225.4		910.7		831.9
Depreciation, depletion and amortization	3.0		2.8		11.9		11.1
Taxes, other than income	6.7		6.9		32.0		29.1
	237.2		235.1		954.6		872.1
Operating income	21.5		14.0		85.2		66.5
Earnings	$	15.5	$	8.5	$	52.2	$	38.4

The combined construction businesses reported earnings of $103.1 million, compared to $70.8 million in 2012. The earnings increase reflects higher asphalt, aggregate and other product line margins and volumes at the materials group, as well as higher workloads and margins in the Western Region, and higher equipment sales and rental revenue and margins at the services group.

Fourth quarter earnings for the combined construction businesses were $27.8 million, compared to $16.2 million in 2012. The construction businesses reported higher workloads and margins in the Western Region and higher equipment sales and rental margins at the services group, as well as higher aggregate margins at the materials group.

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 $456 million, compared to $406 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 $459 million, compared to $325 million a year ago. The backlogs include a variety of projects such as highway grading, paving and underground 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 approximate backlog in North Dakota as of Dec. 31 was $97 million. North Dakota backlog was $46 million a year ago.


•	Projected revenues included in the company's 2014 earnings guidance are in the range of $1.6 billion to $1.8 billion for construction materials and $1.0 billion to $1.1 billion for construction services.


•	The company anticipates margins in 2014 to be in line with 2013 margins.


•	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 expanding into new markets.


•	As the country's sixth-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						Twelve Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
	(In millions)
Operating revenues	$	2.8		$	3.4		$	9.6		$	10.4
Operating expenses:
Operation and maintenance	(.5		)	(1.0		)	.8			3.3
Depreciation, depletion and amortization	.5			.5			2.1			2.0
Taxes, other than income	—			—			.1			.2
	—			(.5		)	3.0			5.5
Operating income	2.8			3.9			6.6			4.9
Income from continuing operations	3.0			2.9			5.1			4.8
Income (loss) from discontinued operations, net of tax	—			8.7			(.3		)	13.6
Earnings	$	3.0		$	11.6		$	4.8		$	18.4

Earnings were $4.8 million in 2013, compared to $18.4 million in 2012. The earnings decrease resulted from the absence in 2013 of the 2012 net benefit of $13.0 million after tax related to the reversal of an arbitration charge related to a guarantee of a construction contract at the domestic power production business, which was sold in 2007.

Fourth quarter earnings were $3.0 million, compared to $11.6 million in 2012. The earnings decrease resulted from the absence in 2013 of the 2012 net benefit related to the reversal of an arbitration charge, as previously discussed, partially offset by the reversal of estimated insurance recoveries related to this matter.

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, 2013 and 2012:


•	A write-down of oil and natural gas properties of $145.9 million after tax in 2012.


•	A reversal of an arbitration charge of $1.5 million after tax in 2013.


•	An unrealized commodity derivatives loss of $500,000 after tax in 2013 and $200,000 after tax in 2012.

Twelve Months Ended December 31, 2013 and 2012:


•	Write-downs of oil and natural gas properties of $246.8 million after tax in 2012.


•	A reversal of an arbitration charge of $1.5 million after tax in 2013 and $15.0 million after tax in 2012.


•	Natural gas gathering asset impairments of $9.0 million after tax in 2013 and $1.7 million after tax in 2012.


•	An unrealized commodity derivatives loss of $3.9 million after tax in 2013 and $400,000 after tax in 2012.

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.


•	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.

•

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 downward movements in prices, could result in additional future noncash write-downs 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 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.


•	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,
	2013			2012			2013			2012
	(In millions, except per share amounts)
	(Unaudited)
Operating revenues	$	1,184.4		$	1,081.1		$	4,462.4		$	4,075.4
Operating expenses:
Fuel and purchased power	23.8			21.1			83.5			72.4
Purchased natural gas sold	199.8			146.2			505.1			425.2
Operation and maintenance	673.1			649.2			2,805.7			2,631.5
Depreciation, depletion and amortization	98.0			98.3			386.8			359.2
Taxes, other than income	42.6			44.1			188.4			176.1
Write-downs of oil and natural gas properties	—			231.7			—			391.8
	1,037.3			1,190.6			3,969.5			4,056.2
Operating income (loss)	147.1			(109.5		)	492.9			19.2
Earnings (loss) from equity method investments	.2			1.4			(.1		)	5.4
Other income	1.8			2.6			6.8			6.6
Interest expense	20.6			19.8			84.0			76.7
Income (loss) before income taxes	128.5			(125.3		)	415.6			(45.5		)
Income taxes	37.2			(55.6		)	136.7			(31.2		)
Income (loss) from continuing operations	91.3			(69.7		)	278.9			(14.3		)
Income (loss) from discontinued operations, net of tax	—			8.7			(.3		)	13.6
Net income (loss)	91.3			(61.0		)	278.6			(.7		)
Net loss attributable to noncontrolling interest	(.2		)	—			(.3		)	—
Dividends declared on preferred stocks	.2			.2			.7			.7
Earnings (loss) on common stock	$	91.3		$	(61.2	)	$	278.2		$	(1.4	)

Earnings (loss) per common share – basic:
Earnings (loss) before discontinued operations	$	.48		$	(.37	)	$	1.47		$	(.08	)
Discontinued operations, net of tax	—			.05			—			.07
Earnings (loss) per common share – basic	$	.48		$	(.32	)	$	1.47		$	(.01	)
Earnings (loss) per common share – diluted:
Earnings (loss) before discontinued operations	$	.48		$	(.37	)	$	1.47		$	(.08	)
Discontinued operations, net of tax	—			.05			—			.07
Earnings (loss) per common share – diluted	$	.48		$	(.32	)	$	1.47		$	(.01	)
Dividends declared per common share	$	.1775		$	.1725		$	.6950		$	.6750
Weighted average common shares outstanding – basic	188.9			188.8			188.9			188.8
Weighted average common shares outstanding – diluted	189.8			188.8			189.7			188.8



	Twelve Months Ended
	December 31,
	2013			2012
	(Unaudited)

Other Financial Data
Book value per common share	$	15.01		$	13.95
Market price per common share	$	30.55		$	21.24
Dividend yield (indicated annual rate)	2.3		%	3.2		%
Price/earnings ratio*	20.0x			18.3		x
Market value as a percent of book value	203.5		%	152.3		%
Net operating cash flow**	$	742		$	585
Total assets**	$	7,061		$	6,682
Total equity**	$	2,856		$	2,648
Total debt **	$	1,866		$	1,773
Capitalization ratios: ***
Total equity	60.5		%	59.9		%
Total debt	39.5			40.1
	100.0		%	100.0		%

* Represents 12 months ended. Based on adjusted earnings.

** In millions

*** Includes noncontrolling interest

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MDU RESOURCES GROUP INC Reports