MDU RESOURCES GROUP INC - FORM 8-K - EX-99 - EXHIBIT 99 - August 4, 2014

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MDU Resources Reports Higher Second Quarter Earnings
•
Construction services business has record second quarter earnings.
•
Construction materials has higher backlog of $764 million; combined construction business backlog totaled $1.15 billion.
•
Oil production grows 14 percent; Fidelity recently announced pending sale of certain Mountrail County, North Dakota production assets.
•
Pipeline and energy services more than doubles earnings; diesel topping plant construction on schedule, approximately 75 percent complete.
•
Utility earnings improve $4.8 million despite mild weather.
•
Earnings per share guidance reaffirmed in range of $1.50 to $1.65.

BISMARCK, N.D. - Aug. 4, 2014 - MDU Resources Group, Inc. (NYSE:MDU) today reported second quarter consolidated adjusted earnings of $56.7 million, or 29 cents per common share, compared to $47.2 million, or 25 cents per common share for the second quarter of 2013. Consolidated GAAP earnings were $53.9 million, or 28 cents per common share, compared to $46.3 million, or 24 cents per common share for the second quarter of 2013. 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.

Adjusted earnings for the six months ended June 30 were $117.4 million, or 61 cents per share, compared to $107.3 million, or 57 cents per share a year ago. Consolidated year-to-date GAAP earnings were $110.4 million, or 58 cents per share, compared to $102.7 million, or 54 cents per share in 2013.

"We are pleased to continue our strong 2014 performance with another good quarter," said David L. Goodin, president and CEO of MDU Resources. "In fact, this is our strongest first half since 2008. It reflects the focus our businesses have on performance and execution of their strategic growth plans."

The construction services business had a record second quarter, led by continuing strong performance by the outside electric group. At the construction materials business, higher aggregate margins and volumes offset lower construction margins including weather-related delays, resulting in the strongest second quarter since 2009. The combined construction business backlog is $1.15 billion.




1


Fidelity Exploration & Production Company continued its oil focus for rebalancing its production portfolio with a 14 percent quarter-over-quarter increase in oil production. The growth was led by a 42 percent increase in production from the Paradox Basin and contributions from properties in Wyoming’s southern Powder River Basin, which were acquired in March. Natural gas production declined 18 percent, in large part because of the divestiture of Green River Basin assets in late 2013. Earnings were impacted by a net reduction in realized commodity derivatives and increased depreciation, depletion and amortization expense.

Fidelity recently announced that it has signed an agreement to sell a portion of its producing properties in Mountrail County, North Dakota. The sale is part of Fidelity’s business strategy of acquiring and developing assets, capturing upside through monetization and redeploying the capital to repeat the growth cycle.

Despite mild weather, the utility had an earnings improvement this quarter. Electric sales grew 4 percent driven by continued strong customer growth combined with positive adjustments to electric and natural gas rates that reflected higher capital investments. Mild weather particularly in the western states resulted in lower natural gas sales.

The pipeline and energy services business more than doubled quarter-over-quarter earnings. The business continued to benefit from its 50 percent ownership in the Pronghorn gathering and processing facility, which had higher oil gathering and processing volumes. Pipeline operations benefited from the favorable settlement of a rate case with new rates going into effect May 1 as well as lower operation and maintenance expense.

Construction of the Dakota Prairie diesel refinery, a joint venture with Calumet Specialty Products Partners, is on budget and approximately 75 percent complete. The refinery remains on schedule for startup at year-end.

"We are pleased with the company’s performance thus far in 2014," Goodin said. "Our expectations remain high for the remainder of the year, although we recognize that favorable weather will be important to performance at several of our businesses. We are maintaining our earnings guidance range of $1.50 to $1.65 per share despite the effects of the Mountrail County asset sale."

The company will host a webcast at 10 a.m. EDT Tuesday, Aug. 5, to discuss earnings results. 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 66196294.

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.


2


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







3


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
Second Quarter 2014 Adjusted Earnings
Second Quarter 2013 Adjusted Earnings
YTD June 30, 2014 Adjusted Earnings
YTD June 30, 2013 Adjusted Earnings
 
(In millions)
Exploration and production
$
22.5

$
24.8

$
47.6

$
48.7

Regulated




 
 
Electric and natural gas utilities
3.3

(1.5
)
41.7

40.8

Pipeline and energy services
5.8

2.6

10.1

4.9

Construction materials and services
24.9

22.9

17.9

14.1

Other and eliminations
.2

(1.6
)
.1

(1.2
)
Adjusted earnings
$
56.7

$
47.2

$
117.4

$
107.3


Reconciliation of GAAP to Adjusted Earnings

Second Quarter 2014 Earnings
Second Quarter 2013 Earnings
YTD June 30, 2014 Earnings
YTD June 30, 2013 Earnings

(In millions, except per share amounts)
Earnings on common stock
$
53.9

$
46.3

$
110.4

$
102.7

Adjustments net of tax:








Discontinued operations
(.5
)
.1

(.5
)
.2

Unrealized (gain) loss on commodity derivatives
3.3

(8.2
)
7.5

(4.6
)
Natural gas gathering asset impairment
—

9.0

—

9.0

Adjusted earnings
$
56.7

$
47.2

$
117.4

$
107.3

Adjusted earnings per share
$
.29

$
.25

$
.61

$
.57


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 $1.50 to $1.65. 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.

4


•
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.
•
Estimated gross capital expenditures for 2014 are approximately $1.1 billion. The estimate excludes noncontrolling interest capital expenditures related to Dakota Prairie Refining.





5


Exploration and Production

Three Months Ended
Six Months Ended

June 30,
June 30,

2014

2013

2014

2013


(Dollars in millions, where applicable)
Operating revenues:




Oil
$
127.2

$
105.9

$
240.8

$
205.9

Natural gas liquids
6.3

6.2

13.2

13.7

Natural gas
21.6

23.2

52.1

42.4

Realized gain (loss) on commodity derivatives
(10.3
)
1.3

(17.1
)
5.6

Unrealized gain (loss) on commodity derivatives
(5.2
)
13.0

(11.9
)
7.2


139.6

149.6

277.1

274.8

Operating expenses:








Operation and maintenance:








Lease operating costs
23.9

22.0

48.0

42.8

Gathering and transportation
3.1

4.2

5.4

8.5

Other
11.8

10.3

23.7

20.4

Depreciation, depletion and amortization
52.9

45.1

102.4

88.3

Taxes, other than income:






Production and property taxes
14.2

12.3

27.1

23.9

Other
.2

.3

.6

.6


106.1

94.2

207.2

184.5

Operating income
33.5

55.4

69.9

90.3

Earnings
$
19.2

$
33.0

$
40.1

$
53.3

Unrealized (gain) loss on commodity derivatives
3.3

(8.2
)
7.5

(4.6
)
Adjusted earnings
$
22.5

$
24.8

$
47.6

$
48.7

Production:








Oil (MBbls)
1,366

1,201

2,646

2,319

Natural gas liquids (MBbls)
167

191

331

392

Natural gas (MMcf)
5,756

6,987

11,034

13,700

Total Production (MBOE)
2,492

2,557

4,816

4,995

Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives):







Oil (per barrel)
$
93.06

$
88.12

$
90.99

$
88.75

Natural gas liquids (per barrel)
$
37.67

$
32.26

$
39.94

$
34.86

Natural gas (per Mcf)
$
3.76

$
3.33

$
4.72

$
3.10

Average realized prices (including realized gain/loss on commodity derivatives):







Oil (per barrel)
$
87.03

$
90.55

$
86.43

$
91.18

Natural gas liquids (per barrel)
$
37.67

$
32.26

$
39.94

$
34.86

Natural gas (per Mcf)
$
3.40

$
3.09

$
4.27

$
3.09

Average depreciation, depletion and amortization rate, per BOE
$
20.45

$
16.90

$
20.45

$
16.90

Production costs, including taxes, per BOE:





Lease operating costs
$
9.57

$
8.59

$
9.97

$
8.57

Gathering and transportation
1.24

1.66

1.13

1.71

Production and property taxes
5.68

4.81

5.63

4.78


$
16.49

$
15.06

$
16.73

$
15.06

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.

6


Second quarter adjusted earnings at this segment were $22.5 million in 2014, compared to $24.8 million in 2013. This decrease reflects a net reduction in realized commodity derivatives, higher depreciation, depletion and amortization expense and decreased natural gas production. Partially offsetting this earnings decrease were higher oil production of 14 percent, largely related to the March Powder River Basin acquisition and the Paradox Basin, as well as higher average realized oil prices. GAAP earnings were $19.2 million in second quarter 2014, compared to $33.0 million in the same period last year.

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

•
The company expects to spend approximately $620 million in gross capital expenditures in 2014, which is likely to be partially offset by the expected sale of certain Mountrail County, North Dakota assets and other planned asset sales this year.
•
For 2014, the company now expects a 10 to 15 percent increase in oil production, lower than its earlier estimate primarily the result of the expected sale of certain Mountrail County assets. Natural gas liquids production is expected to decline 20 to 25 percent and natural gas production is expected to be 20 to 25 percent lower compared to a year ago. The declines are primarily the result of the divestment of certain non-strategic natural gas-based properties in 2013 and the expected divestment of the company's South Texas assets this year. The vast majority of the capital program is focused on growing oil production.
•
The company has a total of three operated drilling rigs deployed on its acreage with two deployed in the Bakken area and one in the Paradox area. There are two non-operated rigs deployed on the company's Powder River Basin acreage.
•
Bakken areas
◦
The company owns a total of approximately 108,500 net acres of leaseholds in Mountrail and Stark counties, North Dakota and Richland County, Montana, assuming the divestment of 4,363 net acres in Mountrail County. 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 $125 million in 2014, excluding the proceeds from the pending sale of Mountrail County acreage.
◦
Net oil production for the second quarter was approximately 7,600 barrels of oil per day.
◦
The company has been testing two alternative completion techniques; plug and perforation and coil tubing with cemented liners. The coil tubing with cemented liner technique is encouraging and focus is on optimizing this approach.
•
Paradox Basin, Utah
◦
The company owns approximately 140,000 net acres of leaseholds, including its acquisitions of 35,000 net acres of leaseholds in February, and 11,000 net acres of leaseholds in April and has an option to earn another 20,000 acres.
◦
Capital expenditures are expected to total approximately $150 million in 2014.
◦
Well costs range from $8 million to $11 million per well depending upon lateral lengths. Estimated ultimate recoveries are increasing with the upper range now at 1.7 MMBO per well.
◦
The Cane Creek Unit 12-1 well has cumulative production of 740 MBO since it began producing in September 2012. Artificial lift facilities have recently been installed.
◦
Net oil production for second quarter was approximately 3,290 BOPD, up 42 percent from second quarter 2013 and down 8 percent from first quarter 2014. Operational issues/downtime on several high-rate wells occurred during the quarter, which have now been broadly resolved with the installation of artificial lift. Drilling on multi-well pads, which defers completion, and two low-rate fringe acreage tests have delayed production growth. Higher growth is expected in third

7


quarter. The second drilling rig will return when sufficient permits are in place to sustain two rigs.
◦
The company's understanding of this play continues to improve. It is anticipated that this field will play a key role in the company's oil growth strategy.
•
Powder River Basin, Wyoming
◦
In March the company acquired 24,500 net acres of leaseholds in Converse County, Wyoming.
◦
Capital expenditures are expected to total approximately $260 million in 2014, including the acquisition costs, related closing adjustments and drilling capital.
◦
Net production for the second quarter was 2,000 BOEPD (75 percent oil), up 23 percent from late March average net production of 1,630 BOEPD.
•
Earnings guidance reflects estimated average NYMEX index prices for August through December in the range of $96 to $102 per barrel of crude oil, and $4.00 to $5.00 per Mcf of natural gas. Estimated prices for natural gas liquids are in the range of $37 to $40 per barrel.
•
Derivatives:
◦
For July through December 2014, 12,000 BOPD at a weighted average price of $96.47.
◦
For July through December 2014, 40,000 MMBtu of natural gas per day at a weighted average price of $4.10.
◦
For January through March 2015, 3,000 BOPD at a weighted average price of $98.00.
◦
For 2015, 10,000 MMBtu of natural gas per day at a weighted average price of $4.28.
◦
The commodity derivative instruments that are in place as of Aug. 1 are summarized in the following chart:

Commodity
Type
Index
Period
Outstanding
Forward Notional Volume
(Bbl/MMBtu)
Price
(Per Bbl/MMBtu)
Crude Oil
Swap
NYMEX
7/14 - 12/14
184,000
$94.05
Crude Oil
Swap
NYMEX
7/14 - 12/14
184,000
$95.00
Crude Oil
Swap
NYMEX
7/14 - 9/14
184,000
$95.75
Crude Oil
Swap
NYMEX
7/14 - 9/14
184,000
$96.00
Crude Oil
Swap
NYMEX
7/14 - 9/14
92,000
$96.25
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
Crude Oil
Swap
NYMEX
7/14 - 12/14
368,000
$96.00
Crude Oil
Swap
NYMEX
10/14 - 12/14
276,000
$100.50
Crude Oil
Swap
NYMEX
10/14 - 12/14
184,000
$101.50
Crude Oil
Swap
NYMEX
1/15 - 3/15
270,000
$98.00
Natural Gas
Swap
NYMEX
7/14 - 12/14
3,680,000
$4.13
Natural Gas
Swap
NYMEX
7/14 - 12/14
1,840,000
$4.05
Natural Gas
Swap
NYMEX
7/14 - 12/14
1,840,000
$4.10
Natural Gas
Swap
NYMEX
1/15 - 12/15
3,650,000
$4.28


8


Regulated
Electric and Natural Gas Utilities

Electric



Three Months Ended
Six Months Ended

June 30,
June 30,

2014

2013

2014

2013


(Dollars in millions, where applicable)
Operating revenues
$
65.1

$
57.0

$
138.8

$
121.6

Operating expenses:





 
Fuel and purchased power
21.1

18.2

47.6

39.8

Operation and maintenance
20.5

20.5

38.9

36.8

Depreciation, depletion and amortization
8.5

7.9

17.1

16.5

Taxes, other than income
2.8

2.8

5.7

5.7

 
52.9

49.4

109.3

98.8

Operating income
12.2

7.6

29.5

22.8

Earnings
$
7.8

$
4.4

$
18.9

$
14.2

Retail sales (million kWh)
721.5

691.5

1,650.4

1,534.1

Average cost of fuel and purchased power per kWh
$
.027

$
.024

$
.027

$
.024






Natural Gas Distribution

 

 

Three Months Ended
Six Months Ended

June 30,
June 30,

2014

2013

2014

2013


(Dollars in millions)
Operating revenues
$
146.1

$
127.6

$
520.3

$
459.3

Operating expenses:





 
Purchased natural gas sold
89.1

73.5

346.4

286.9

Operation and maintenance
35.9

35.7

73.8

69.9

Depreciation, depletion and amortization
13.5

12.4

26.8

24.5

Taxes, other than income
9.9

9.5

27.8

25.7

 
148.4

131.1

474.8

407.0

Operating income (loss)
(2.3
)
(3.5
)
45.5

52.3

Earnings (loss)
$
(4.5
)
$
(5.9
)
$
22.8

$
26.6

Volumes (MMdk):


 


 
Sales
14.7

15.3

60.0

60.2

Transportation
29.9

30.3

69.2

68.5

Total throughput
44.6

45.6

129.2

128.7

Degree days (% of normal)*
 
 
 
 
Montana-Dakota/Great Plains
109
%
130
%
107
%
104
%
Cascade
78
%
82
%
93
%
93
%
Intermountain
95
%
99
%
96
%
110
%
* Degree days are a measure of the daily temperature-related demand for energy for heating.


9


The combined utility businesses reported earnings of $3.3 million in the second quarter of 2014, compared to a loss of $1.5 million for the same period in 2013. This increase reflects higher electric retail sales margins, primarily the result of higher rates related to the recovery of costs of environmental upgrades; as well as approved natural gas retail rate increases effective in late 2013. Lower natural gas sales volumes resulting from warmer weather partially offset the increase.

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 Feb. 27 with the North Dakota Public Service Commission requesting approval for a generation resource recovery rider for $7.4 million to recover costs associated with the 88-megawatt simple-cycle natural gas turbine and associated facilities currently under construction. The estimated project cost is $77 million and the projected in-service date is third quarter 2014. It is located adjacent to the company's Heskett Generating Station near Mandan, North Dakota. 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. On March 12, the commission suspended the filing pending further review and a hearing was held May 28. A work session was held July 18 to discuss the request. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the commission.
◦
The company filed an application Sept. 18 with the NDPSC for a natural gas rate increase including 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. A settlement agreement was approved by the commission for an increase in the same amount as the interim increase. Final rates have been approved and were implemented May 1.
◦
The company submitted a request April 8 to the NDPSC to update an environmental cost recovery rider related to costs resulting from the environmental retrofit required to be installed at the Big Stone Station to reflect actual costs incurred through February and projected costs through June 2015. The commission approved the rider July 10 for recovery of $8.6 million annually. 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.
•
Investments are being made in 2014 totaling approximately $80 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.

10


•
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, 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 with the state of North Dakota. A route permit was approved in North Dakota on July 10. A route permit hearing was held June 10 in South Dakota. The project is expected to be complete in 2019.
•
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
 
Six Months Ended


June 30,
 
June 30,


2014

2013

 
2014

2013



(Dollars in millions)

Operating revenues
$
51.4

$
50.9

 
$
113.3

$
97.3


Operating expenses:




 


 


Purchased natural gas sold
13.0

15.8

 
39.2

28.6


Operation and maintenance
16.9

32.1

*
33.6

49.3

*
Depreciation, depletion and amortization
7.2

7.7

 
14.3

14.9


Taxes, other than income
3.4

3.5

 
6.6

6.9


 
40.5

59.1

 
93.7

99.7


Operating income (loss)
10.9

(8.2
)
 
19.6

(2.4
)

Earnings (loss)
$
5.8

$
(6.4
)
*
$
10.1

$
(4.1
)
*
Natural gas gathering asset impairment
—

9.0

 
—

9.0


Adjusted earnings
$
5.8

$
2.6

 
$
10.1

$
4.9


Transportation volumes (MMdk)
53.3

40.3

 
105.8

77.1


Natural gas gathering volumes (MMdk)
9.7

10.0

 
19.1

19.9


Customer natural gas storage balance (MMdk):




 


 


Beginning of period
10.4

24.7

 
26.7

43.7


Net injection (withdrawal)
1.0

.5

 
(15.3
)
(18.5
)

End of period
11.4

25.2

 
11.4

25.2


* Reflects an impairment of coalbed natural gas gathering assets of $14.5 million ($9.0 million after tax).

This segment reported second quarter adjusted earnings of $5.8 million, compared to $2.6 million in 2013. The 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 rates and lower operation and maintenance expense. Lower storage services revenue partially offset the increase.


11


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 and it is approximately 75 percent complete. 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 is 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.
•
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. The open season ended May 30 and the company is evaluating the responses received and working with those parties as well as other interested parties. The company expects to provide a status update on its efforts by this fall. If the project moves forward, following the receipt of necessary permits and regulatory approvals, construction on the new pipeline could begin in 2016 with completion expected in 2017.
•
On Oct. 31, WBI Energy Transmission filed a Section 4 rate case with the FERC based on an increase in investments and increased operating costs since 1999. On April 30 a settlement was reached with the parties involved. The presiding administrative law judge issued a certification of uncontested settlement June 11 recommending FERC approval of the settlement without modification. Proposed settlement rates were implemented May 1, pending final approval. Based on the adjusted base period volumes filed in the case, the annual increase in revenues is approximately $11.5 million.
•
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.




12


Construction

Construction Materials and Contracting

 

 

Three Months Ended
Six Months Ended

June 30,
June 30,

2014

2013

2014

2013


(Dollars in millions)
Operating revenues
$
442.6

$
431.3

$
611.0

$
597.6

Operating expenses:





 
Operation and maintenance
393.4

381.2

569.1

547.9

Depreciation, depletion and amortization
17.4

18.7

35.0

37.7

Taxes, other than income
10.6

10.6

18.9

19.1

 
421.4

410.5

623.0

604.7

Operating income (loss)
21.2

20.8

(12.0
)
(7.1
)
Earnings (loss)
$
10.6

$
10.0

$
(13.0
)
$
(10.5
)
Sales (000's):





 
Aggregates (tons)
6,971

6,152

9,800

9,110

Asphalt (tons)
1,474

1,518

1,658

1,667

Ready-mixed concrete (cubic yards)
907

846

1,404

1,326

Construction Services

 




Three Months Ended
Six Months Ended

June 30,
June 30,

2014

2013

2014

2013


(In millions)
Operating revenues
$
282.3

$
279.6

$
556.0

$
511.0

Operating expenses:





 
Operation and maintenance
246.5

245.9

480.6

444.3

Depreciation, depletion and amortization
3.2

3.0

6.4

6.0

Taxes, other than income
8.3

8.4

18.5

18.0

 
258.0

257.3

505.5

468.3

Operating income
24.3

22.3

50.5

42.7

Earnings
$
14.3

$
12.9

$
30.9

$
24.6


The combined construction businesses reported earnings of $24.9 million in the second quarter of 2014, compared to $22.9 million a year ago. The increase in earnings reflects higher aggregate margins and volumes, partially offset by lower construction margins at the materials group; as well as record earnings at the services group with higher margins in the Central region primarily related to outside work.

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

•
The construction businesses had combined work backlog of $1.15 billion as of June 30 compared to $1.18 billion a year ago. Construction materials' approximate backlog as of June 30 was higher at $764 million, compared to $730 million a year ago. Private work represents 11 percent of construction backlog and public work represents 89 percent of backlog. The June 30 approximate backlog at construction services was down to $386 million, compared to $447 million a year ago. Bidding opportunities are strong and additional backlog has been secured since June 30. The backlogs include a variety of projects such as highway grading, paving and underground projects,

13


airports, bridge work, subdivisions, 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 June 30 was $169 million. North Dakota backlog was $165 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 $1.1 billion to $1.2 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 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.

Other


Three Months Ended
Six Months Ended

June 30,
June 30,

2014

2013

2014

2013


(In millions)
Operating revenues
$
2.2

$
2.3

$
4.3

$
4.5

Operating expenses:







Operation and maintenance
1.1

1.4

2.5

2.7

Depreciation, depletion and amortization
.6

.5

1.1

1.0

Taxes, other than income
—

—

—

.1

 
1.7

1.9

3.6

3.8

Operating income
.5

.4

.7

.7

Income from continuing operations
1.1

.5

1.3

.9

Income (loss) from discontinued operations, net of tax
.5

(.1
)
.5

(.2
)
Earnings
$
1.6

$
.4

$
1.8

$
.7


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 June 30, 2014 and 2013:
•
An unrealized loss on commodity derivatives of $3.3 million after tax in 2014, and an unrealized gain on commodity derivatives of $8.2 million after tax in 2013.
•
Natural gas gathering asset impairment of $9.0 million after tax in 2013.

Six Months Ended June 30, 2014 and 2013:
•
An unrealized loss on commodity derivatives of $7.5 million after tax in 2014, and an unrealized gain on commodity derivatives of $4.6 million after tax in 2013.
•
Natural gas gathering asset impairment of $9.0 million after tax in 2013.


14


Twelve Months Ended June 30, 2014:
•
An unrealized loss on commodity derivatives of $15.9 million after tax.
•
A reversal of an arbitration charge of $1.5 million after tax.

Twelve Months Ended June 30, 2013:
•
Natural gas gathering asset impairment of $9.0 million after tax.
•
An unrealized gain on commodity derivatives of $3.8 million after tax.
•
Write-downs of oil and natural gas properties of $246.8 million after tax.

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.

15


•
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.

16


MDU Resources Group, Inc.
 
 
 
Three Months Ended
Six Months Ended
 
June 30,
June 30,
 
2014

2013

2014

2013

 
(In millions, except per share amounts)
 
(Unaudited)
Operating revenues
$
1,094.0

$
1,060.6

$
2,136.9

$
1,992.2

Operating expenses:
 
 
 
 
Fuel and purchased power
21.1

18.2

47.6

39.8

Purchased natural gas sold
84.4

70.2

329.3

269.4

Operation and maintenance
737.1

738.1

1,250.3

1,198.2

Depreciation, depletion and amortization
103.1

95.3

202.7

188.9

Taxes, other than income
49.4

47.4

105.2

100.0

 
995.1

969.2

1,935.1

1,796.3

Operating income
98.9

91.4

201.8

195.9

Loss from equity method investments
(.3
)
—

(.2
)
(.3
)
Other income
2.8

1.4

4.9

2.7

Interest expense
21.5

21.4

42.5

42.3

Income before income taxes
79.9

71.4

164.0

156.0

Income taxes
27.1

25.0

55.0

53.0

Income from continuing operations
52.8

46.4

109.0

103.0

Income (loss) from discontinued operations, net of tax
.5

(.1
)
.5

(.2
)
Net income
53.3

46.3

109.5

102.8

Net loss attributable to noncontrolling interest
(.8
)
(.2
)
(1.3
)
(.2
)
Dividends declared on preferred stocks
.2

.2

.4

.3

Earnings on common stock
$
53.9

$
46.3

$
110.4

$
102.7

 








Earnings per common share – basic:








Earnings before discontinued operations
$
.28

$
.25

$
.58

$
.54

Discontinued operations, net of tax
—

—

—

—

Earnings per common share – basic
$
.28

$
.25

$
.58

$
.54

Earnings per common share – diluted:








Earnings before discontinued operations
$
.28

$
.24

$
.58

$
.54

Discontinued operations, net of tax
—

—

—

—

Earnings per common share – diluted
$
.28

$
.24

$
.58

$
.54

Dividends declared per common share
$
.1775

$
.1725

$
.3550

$
.3450

Weighted average common shares outstanding – basic
192.1

188.8

190.9

188.8

Weighted average common shares outstanding – diluted
192.7

189.5

191.5

189.5




17




Six Months Ended

June 30,

2014

 
2013


(Unaudited)
Other Financial Data


 


Book value per common share
$
15.75

 
$
14.19

Market price per common share
$
35.10

 
$
25.91

Dividend yield (indicated annual rate)
2.0
%
 
2.7
%
Price/adjusted earnings ratio*
22.2
x
 
19.2
x
Market value as a percent of book value
222.9
%
 
182.6
%
Net operating cash flow**
$
211

 
$
234

Total assets**
$
7,668

 
$
7,092

Total equity**
$
3,064

 
$
2,695

Total debt **
$
2,187

 
$
2,038

Capitalization ratios: ***


 


Total equity
58.4
%
 
56.9
%
Total debt
41.6

 
43.1


100.0
%
 
100.0
%
    *    Represents 12 months ended. Based on adjusted earnings.
  **    In millions
*** Includes noncontrolling interest




18

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MDU RESOURCES GROUP INC Reports