EX-99 2 mduq32014earningrelease.htm MDU 11-3-2014 EARNINGS RELEASE Wdesk | MDU Q3 2014 Earning Release


MDU Resources Reports Third Quarter Earnings;
Announces Evaluating Second Diesel Refinery and
Marketing Its Fidelity Exploration & Production Company
•
Construction materials has record quarterly earnings, up 12 percent on 5 percent revenue growth.
•
Pipeline and energy services on schedule to bring Dakota Prairie diesel refinery on line by end of the year; announces evaluating second diesel refinery.
•
Utility continues record capital program with strong customer growth, 5 percent electric and 3 percent natural gas in Bakken.
•
Company to market Fidelity Exploration & Production business.

BISMARCK, N.D. - Nov. 3, 2014 - MDU Resources Group, Inc. (NYSE:MDU) today reported third quarter consolidated adjusted earnings of $84.9 million, or 44 cents per common share, compared to $92.3 million, or 49 cents per common share for the third quarter of 2013. Consolidated GAAP earnings were $103.0 million, or 53 cents per common share, compared to $84.3 million, or 44 cents per common share for the third 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 nine months ended September 30 were $202.3 million, or $1.05 per share, compared to $199.6 million, or $1.05 per share a year ago. Consolidated year-to-date GAAP earnings were $213.5 million, or $1.11 per share, compared to $187.0 million, or 99 cents per share in 2013.

The company also announced that it plans to market its Fidelity Exploration & Production business. "Although we continue to see attractive investment opportunities at Fidelity, the capital required to effectively grow the business would compromise our ability to fund the substantial opportunities we are seeing at our other lines of business," said David L. Goodin, president and CEO of MDU Resources Group. "We expect to grow our utility, pipeline and construction business units in a more meaningful way and pursue that growth with a lower overall business-risk profile." The company has engaged Goldman Sachs as its financial advisor.
The company’s construction materials business had a record quarter, with earnings of $55.2 million. Construction workloads and margins, ready-mixed concrete margins and volumes and asphalt margins increased. Outside construction work was strong at the construction services group, which had earnings of $9.9 million. The construction services group earnings year-to-date are at a near-record pace.

"Our construction materials business has taken advantage of continuing improvements in the economy, and also is benefiting from favorable weather that is extending the final stages of the construction season," Goodin said. "Those conditions and outstanding performance turned this into the best quarter ever for that business."

The construction businesses are seeing strong bidding opportunities as regional economies improve.

1



Earnings of $9.2 million at the electric utility business were affected by a 3 percent decline in sales to residential customers, as cooler than normal weather lessened customer air conditioning usage. O&M expenses related to payroll and benefits increased, partially offset by rate recovery for environmental upgrades. The natural gas business experienced a normal seasonal loss of $12.3 million.

The utility group has a record capital program it is executing on including an $80 million investment in infrastructure in the Bakken this year and the completion in August of an 88-megawatt gas turbine in North Dakota. The electric group is planning for additional new generation with the potential for renewables to be added to the portfolio to meet its growing customer demand.

Earnings at the pipeline and energy services business totaled $5.1 million as its investment in the Pronghorn natural gas and oil midstream assets continued to produce good results on the strength of higher gathering and processing volumes and new rates were implemented related to a rate case settlement. Construction of a diesel refinery in western North Dakota is approximately 90 percent complete and remains on schedule for startup by the end of 2014.

In addition, WBI Energy is evaluating the construction of a second 20,000-barrel-per-day diesel topping plant to be located in the Bakken region of North Dakota. A preferred site has been identified and permitting work has begun. A spring 2015 construction start is planned should the evaluation warrant proceeding with a second plant.

The pipeline group is also working on plans for the Wind Ridge Pipeline project, a 95-mile natural gas pipeline designed to deliver approximately 90 million cubic feet per day to an announced fertilizer plant near Spiritwood, North Dakota.

Fidelity Exploration & Production had adjusted earnings of $16.6 million. Results were primarily driven by 12 percent lower average realized oil prices compared to last year as well as higher DD&A and lease operating expenses. Natural gas production was 27 percent lower largely the result of the sale of non-strategic natural gas assets in 2013. The company recently closed on the sales of certain Mountrail County and South Texas assets.

The company reaffirmed its 2014 annual earnings per share guidance in the range of $1.40 to $1.50.

"Our focus will continue to be on executing on organic opportunities as well as acquisition-related growth potential that exists at all of our remaining businesses," Goodin said. "We believe we are well positioned to succeed."

The company will host a webcast at 10 a.m. EST Tuesday, Nov. 4, 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 13274434.

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
Third Quarter 2014 Adjusted Earnings
Third Quarter 2013 Adjusted Earnings
YTD Sept. 30, 2014 Adjusted Earnings
YTD Sept. 30, 2013 Adjusted Earnings
 
(In millions)
Regulated




 
 
Electric and natural gas utilities
$
(3.1
)
$
.2

$
38.5

$
41.1

Pipeline and energy services
5.1

5.3

15.2

10.3

Construction materials and services
65.1

61.4

83.0

75.3

Exploration and production
16.6

25.3

64.2

74.1

Other and eliminations
1.2

.1

1.4

(1.2
)
Adjusted earnings
$
84.9

$
92.3

$
202.3

$
199.6

Reconciliation of GAAP to Adjusted Earnings

Third Quarter 2014 Earnings
Third Quarter 2013 Earnings
YTD Sept. 30, 2014 Earnings
YTD Sept. 30, 2013 Earnings

(In millions, except per share amounts)
Earnings on common stock
$
103.0

$
84.3

$
213.5

$
187.0

Adjustments net of tax:








Discontinued operations
—

.1

(.5
)
.2

Unrealized (gain) loss on commodity derivatives
(18.1
)
7.9

(10.7
)
3.4

Natural gas gathering asset impairment
—

—

—

9.0

Adjusted earnings
$
84.9

$
92.3

$
202.3

$
199.6

Adjusted earnings per share
$
.44

$
.49

$
1.05

$
1.05

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

•
Adjusted earnings per share for 2014 are projected in the range of $1.40 to $1.50. 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.
•
Estimated gross capital expenditures for 2014 are approximately $1.1 billion. The estimate excludes noncontrolling interest capital expenditures related to Dakota Prairie Refining.
•
The company announced its intent to market and potentially sell its exploration and production company.

4



Regulated
Electric and Natural Gas Utilities

Electric



Three Months Ended
Nine Months Ended

September 30,
September 30,

2014

2013

2014

2013


(Dollars in millions, where applicable)
Operating revenues
$
69.0

$
68.3

$
207.8

$
189.9

Operating expenses:





 
Fuel and purchased power
19.2

20.0

66.8

59.8

Operation and maintenance
21.4

19.5

60.4

56.4

Depreciation, depletion and amortization
8.8

8.1

25.9

24.6

Taxes, other than income
2.8

2.7

8.4

8.4

 
52.2

50.3

161.5

149.2

Operating income
16.8

18.0

46.3

40.7

Earnings
$
9.2

$
11.4

$
28.0

$
25.7

Retail sales (million kWh)
769.5

795.2

2,420.0

2,329.4

Average cost of fuel and purchased power per kWh
$
.023

$
.024

$
.026

$
.024






Natural Gas Distribution

 

 

Three Months Ended
Nine Months Ended

September 30,
September 30,

2014

2013

2014

2013


(Dollars in millions)
Operating revenues
$
96.2

$
77.5

$
616.5

$
536.8

Operating expenses:





 
Purchased natural gas sold
50.0

36.5

396.3

323.5

Operation and maintenance
38.0

35.1

111.8

104.9

Depreciation, depletion and amortization
13.7

12.7

40.6

37.3

Taxes, other than income
7.7

7.3

35.4

32.9

 
109.4

91.6

584.1

498.6

Operating income (loss)
(13.2
)
(14.1
)
32.4

38.2

Earnings (loss)
$
(12.3
)
$
(11.2
)
$
10.5

$
15.4

Volumes (MMdk):


 


 
Sales
8.8

7.6

68.8

67.7

Transportation
36.9

37.0

106.1

105.6

Total throughput
45.7

44.6

174.9

173.3

Degree days (% of normal)*
 
 
 
 
Montana-Dakota/Great Plains
88
%
34
%
106
%
101
%
Cascade
64
%
74
%
91
%
92
%
Intermountain
84
%
89
%
96
%
109
%
* Degree days are a measure of the daily temperature-related demand for energy for heating.


5


The combined utility businesses reported a loss of $3.1 million in the third quarter of 2014, compared to earnings of $200,000 for the same period in 2013. This decrease reflects higher operation and maintenance expense, largely payroll and benefits related, higher depreciation, depletion and amortization expense, and higher interest expense as well as 3 percent lower electric sales the result of cooler weather effecting air conditioning load. Higher approved natural gas retail rate increases in late 2013 and rate recovery on electric environmental upgrades as well as increased natural gas retail sales volumes partially offset the decrease.

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
◦
July 10 the North Dakota Public Service Commission approved recovery of $8.6 million annually effective July 15 to reflect actual costs incurred through February and projected costs through June 2015 for an environmental cost recovery rider related to costs resulting from the retrofit required to be installed at the Big Stone Station. The company's share of the cost for the installation is approximately $90 million and is expected to be complete in 2015. The commission had earlier approved advance determination of prudence for recovery of costs on the system.
◦
Aug. 11 the company filed an application with the Montana Public Service Commission for a natural gas rate increase of approximately $3.0 million annually, or 3.6 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses. An interim increase of $2.2 million annually, or 2.6 percent was requested, subject to refund.
◦
Aug. 20 the NDPSC approved a settlement agreement to establish a generation resource recovery rider associated with the 88-megawatt simple-cycle natural gas turbine and a provision to recover costs associated with a pipeline to the facility through the fuel and purchased power adjustment mechanism. The agreement allows the company the right to file and implement adjustments if the expected return is below a specified return on equity as well as sharing of earnings in 2014 if earnings exceed the return. The project cost was $77 million and was brought in-service Aug. 5. The capacity is necessary to meet the requirements of the company's integrated electric system customers and is 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 the commission.
◦
Oct. 3 the company filed an application with the Wyoming Public Service Commission for a natural gas rate increase of approximately $788,000 annually, or 4.1 percent above current rates. The requested increase includes the costs associated with the increased investment in facilities and associated depreciation, taxes and operation and maintenance expenses.
◦
The company has planned natural gas rate case filings for Oregon in late 2014 or early 2015 and North Dakota in early 2015. The company expects to file electric rate cases in Montana and South Dakota in 2015.
•
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.

6


•
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 2013 with the state of North Dakota. A route permit was approved in North Dakota on July 10 and South Dakota on Aug. 13. The South Dakota route permit has been appealed. The company continues to expect the project to be complete in 2019.
•
The company is pursuing additional generation projects including renewable resources.
•
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
 
Nine Months Ended


September 30,
 
September 30,


2014

2013

 
2014

2013



(Dollars in millions)

Operating revenues
$
50.7

$
51.3

 
$
164.0

$
148.6


Operating expenses:




 


 


Purchased natural gas sold
9.9

14.0

 
49.1

42.6


Operation and maintenance
20.7

16.1

 
54.4

65.3

*
Depreciation, depletion and amortization
7.4

7.1

 
21.7

22.0


Taxes, other than income
3.4

3.3

 
9.9

10.3


 
41.4

40.5

 
135.1

140.2


Operating income
9.3

10.8

 
28.9

8.4


Earnings
$
5.1

$
5.3

 
$
15.2

$
1.3

*
Natural gas gathering asset impairment
—

—

 
—

9.0


Adjusted earnings
$
5.1

$
5.3

 
$
15.2

$
10.3


Transportation volumes (MMdk)
60.5

52.1

 
166.3

129.2


Natural gas gathering volumes (MMdk)
9.6

10.6

 
28.7

30.5


Customer natural gas storage balance(MMdk):




 


 


Beginning of period
11.4

25.2

 
26.7

43.7


Net injection (withdrawal)
7.0

12.9

 
(8.3
)
(5.6
)

End of period
18.4

38.1

 
18.4

38.1


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

This segment reported third quarter earnings of $5.1 million, compared to $5.3 million in 2013. The earnings decrease reflects higher operation and maintenance expense, primarily due to higher payroll and benefits related costs, as well as lower storage services earnings. The decrease was largely offset by higher transportation rates, primarily resulting from a rate case settlement; as well as higher earnings from its interest in the Pronghorn natural gas and oil midstream assets, primarily from higher volumes.


7


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 is near 90 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 $360 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 $60 million to $80 million, to be shared equally with Calumet.
•
The company is developing plans for its Wind Ridge Pipeline project, a 95-mile natural gas pipeline designed to deliver approximately 90 million cubic feet per day to an announced fertilizer plant near Spiritwood, North Dakota. The project cost is estimated to be approximately $120 million with an in-service date in 2017.
•
The company is in the process of pursuing 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 and Viking Gas Transmission in northwestern Minnesota. 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.
•
Aug. 11 the Federal Energy Regulatory Commission issued an order approving settlement of new rates effective May 1. Based on the adjusted base period volumes filed in the case, the annual increase in revenues is approximately $11.5 million.
•
The company recently completed connections for the Garden Creek II natural gas processing plant in the Bakken. The company is also engaged in various natural gas pipeline projects being constructed in 2014, including an expansion of its transmission system to increase capacity to the Black Hills and a now substantially complete 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.




8


Construction

Construction Materials and Contracting

 

 

Three Months Ended
Nine Months Ended

September 30,
September 30,

2014

2013

2014

2013


(Dollars in millions)
Operating revenues
$
746.8

$
714.4

$
1,357.8

$
1,312.0

Operating expenses:






Operation and maintenance
627.9

600.9

1,197.0

1,148.8

Depreciation, depletion and amortization
17.0

19.0

52.0

56.7

Taxes, other than income
11.8

11.6

30.7

30.7

 
656.7

631.5

1,279.7

1,236.2

Operating income
90.1

82.9

78.1

75.8

Earnings
$
55.2

$
49.2

$
42.2

$
38.6

Sales (000's):






Aggregates (tons)
10,166

9,902

19,966

19,012

Asphalt (tons)
3,208

3,311

4,866

4,978

Ready-mixed concrete (cubic yards)
1,233

1,132

2,637

2,458

Construction Services

 




Three Months Ended
Nine Months Ended

September 30,
September 30,

2014

2013

2014

2013


(In millions)
Operating revenues
$
286.7

$
270.1

$
842.8

$
781.1

Operating expenses:






Operation and maintenance
258.6

238.8

739.2

683.2

Depreciation, depletion and amortization
3.2

3.0

9.6

8.9

Taxes, other than income
8.0

7.3

26.6

25.3

 
269.8

249.1

775.4

717.4

Operating income
16.9

21.0

67.4

63.7

Earnings
$
9.9

$
12.2

$
40.8

$
36.7


The combined construction businesses reported earnings of $65.1 million in the third quarter of 2014, compared to $61.4 million a year ago. The increase in earnings reflects higher construction workloads and margins, ready-mixed concrete margins and volumes, and higher asphalt margins at the materials group. The increase is offset in part by lower margins and higher selling, general and administrative expense at the services group.

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

•
The construction businesses had combined work backlog of $824 million as of Sept. 30 compared to $958 million a year ago. Construction materials' approximate backlog as of Sept. 30 was $476 million, compared to $525 million a year ago. Private work represents 13 percent of construction backlog and public work represents 87 percent of backlog. The Sept. 30 approximate backlog at construction services was $348 million, compared to $433 million a year ago. Bidding opportunities are strong and additional backlog has been secured since Sept. 30. The backlogs include a variety of projects such as highway grading, paving and underground projects, airports, bridge work, subdivisions, substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.

9


•
The company's approximate backlog in North Dakota as of Sept. 30 was $64 million. North Dakota backlog was $157 million a year ago, which included the $55 million bypass project in the Bakken region. It was the largest project in the company's history and is now substantially complete.
•
Projected revenues included in the company's 2014 earnings guidance are in the range of $1.7 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 anticipates recording a withdrawal liability of approximately $14 million, $8.4 million after tax, related to a multiemployer pension plan in the fourth quarter 2014.
•
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.


10


Exploration and Production
 
Three Months Ended
Nine Months Ended
 
September 30,
September 30,
 
2014

2013

2014

2013

 
(Dollars in millions, where applicable)
Operating revenues:
 
 
 
 
Oil
$
106.4

$
121.4

$
347.2

$
327.3

Natural gas liquids
6.1

7.6

19.3

21.3

Natural gas
16.3

20.1

68.4

62.5

Realized loss on commodity derivatives
(1.8
)
(6.6
)
(18.8
)
(1.0
)
Unrealized gain (loss) on commodity derivatives
28.8

(12.6
)
16.8

(5.4
)
 
155.8

129.9

432.9

404.7

Operating expenses:
 
 
 
 
Operation and maintenance:
 
 
 
 
Lease operating costs
22.0

20.6

70.0

63.4

Gathering and transportation
3.0

3.5

8.5

12.1

Other
10.5

12.5

34.1

32.9

Depreciation, depletion and amortization
53.0

49.6

155.4

137.8

Taxes, other than income:
 
 
 
 
Production and property taxes
11.7

13.3

38.8

37.1

Other
.1

.2

.8

.9

 
100.3

99.7

307.6

284.2

Operating income
55.5

30.2

125.3

120.5

Earnings
$
34.7

$
17.4

$
74.9

$
70.7

Unrealized (gain) loss on commodity derivatives
(18.1
)
7.9

(10.7
)
3.4

Adjusted earnings
$
16.6

$
25.3

$
64.2

$
74.1

Production:
 
 
 
 
Oil (MBbls)
1,251

1,252

3,897

3,571

Natural gas liquids (MBbls)
170

196

501

588

Natural gas (MMcf)
5,336

7,302

16,369

21,002

Total Production (MBOE)
2,309

2,664

7,126

7,659

Average realized prices (excluding realized and unrealized gain/loss on commodity derivatives):
 
 
 
 
Oil (per barrel)
$
85.10

$
97.00

$
89.10

$
91.64

Natural gas liquids (per barrel)
$
35.81

$
39.02

$
38.54

$
36.24

Natural gas (per Mcf)
$
3.06

$
2.75

$
4.18

$
2.98

Average realized prices (including realized gain/loss on commodity derivatives):
 
 
 
 
Oil (per barrel)
$
83.54

$
91.03

$
85.50

$
91.13

Natural gas liquids (per barrel)
$
35.81

$
39.02

$
38.54

$
36.24

Natural gas (per Mcf)
$
3.09

$
2.87

$
3.88

$
3.02

Average depreciation, depletion and amortization rate, per BOE
$
22.10

$
17.90

$
20.98

$
17.25

Production costs, including taxes, per BOE:
 
 
 
Lease operating costs
$
9.54

$
7.74

$
9.82

$
8.28

Gathering and transportation
1.31

1.33

1.19

1.58

Production and property taxes
5.06

4.98

5.45

4.85

 
$
15.91

$
14.05

$
16.46

$
14.71

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.

11


Third quarter adjusted earnings at this segment were $16.6 million in 2014, compared to $25.3 million in 2013. This decrease reflects 12 percent lower average realized oil prices as well as higher depreciation, depletion and amortization and lease operating expenses. Natural gas production was 27 percent lower compared to a year ago largely the result of the sale of non-strategic natural gas assets in 2013. Partially offsetting this earnings decrease was an increase in realized commodity derivatives, higher income tax benefits and higher average realized gas prices. GAAP earnings were $34.7 million in third quarter 2014, compared to $17.4 million in the same period last year.

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

•
The company announced its intent to market and potentially sell its exploration and production company.
•
The company expects to spend approximately $610 million in gross capital expenditures in 2014, which will be partially offset by the completed sales of certain Mountrail County, North Dakota and South Texas assets.
•
For 2014, the company expects a 3 to 7 percent increase in oil production. 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 divestments of certain Mountrail County and 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 one each in the Bakken, Paradox and East Texas areas. There are two or three non-operated rigs deployed on the company's Powder River Basin acreage.
•
Recently closed sales of certain Mountrail County and South Texas assets included approximately 1,900 barrels of oil per day and 4,100 BOEPD.
•
Bakken areas
◦
The company owns a total of approximately 105,500 net acres of leaseholds in Mountrail and Stark counties, North Dakota and Richland County, Montana. 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 completed sale of certain Mountrail County assets.
◦
Net oil production for the third quarter was approximately 7,500 BOPD.
◦
The company is completing new Bakken wells with coil tubing with cemented liners and is seeing good results.
•
Paradox Basin, Utah
◦
The company owns approximately 140,000 net acres of leaseholds and has an option to earn another 20,000 acres.
◦
Capital expenditures are expected to total approximately $150 million in 2014.
◦
Estimated ultimate recoveries have an upper range of 1.7 MMBO per well.
◦
Artificial lift facilities have recently been installed on the higher rate Cane Creek Unit 12-1 and 18-1 wells. The combined producing rate is 600 to 800 BOPD.
◦
Net oil production for third quarter was approximately 2,400 BOPD, up 5 percent from third quarter 2013.
◦
Recently drilled wells have yielded lower than expected results and include tighter rock than the previous drilled high rate wells. As a result, in November the company will test-fracture stimulation a well for the first time in the basin.
•
Powder River Basin, Wyoming
◦
In March, the company acquired approximately 24,500 net acres of leaseholds in Converse County, Wyoming.
◦
Capital expenditures are expected to total approximately $260 million in 2014, including acquisition costs, related closing adjustments and drilling capital.
◦
Net production for the third quarter was 1,685 BOEPD (75 percent oil), up 3 percent from late March average net production of 1,630 BOEPD.
•
Earnings guidance reflects estimated average NYMEX index prices for November through December in the range of $80 to $85 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 $20 to $25 per barrel.

12


•
Derivatives:
◦
For October through December 2014, 12,000 BOPD at a weighted average price of $97.50.
◦
For October 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 Oct. 31 are summarized in the following chart:

Commodity
Type
Index
Period
Outstanding
Forward Notional Volume
(Bbl/MMBtu)
Price
(Per Bbl/MMBtu)
Crude Oil
Swap
NYMEX
10/14 - 12/14
92,000
$94.05
Crude Oil
Swap
NYMEX
10/14 - 12/14
92,000
$94.25
Crude Oil
Swap
NYMEX
10/14 - 12/14
184,000
$95.00
Crude Oil
Swap
NYMEX
10/14 - 12/14
92,000
$95.25
Crude Oil
Swap
NYMEX
10/14 - 12/14
184,000
$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
10/14 - 12/14
1,840,000
$4.13
Natural Gas
Swap
NYMEX
10/14 - 12/14
920,000
$4.05
Natural Gas
Swap
NYMEX
10/14 - 12/14
920,000
$4.10
Natural Gas
Swap
NYMEX
1/15 - 12/15
3,650,000
$4.28

Other


Three Months Ended
Nine Months Ended

September 30,
September 30,

2014

2013

2014

2013


(In millions)
Operating revenues
$
3.1

$
2.3

$
7.3

$
6.8

Operating expenses:







Operation and maintenance
(1.4
)
(1.4
)
1.0

1.2

Depreciation, depletion and amortization
.6

.5

1.6

1.5

Taxes, other than income
—

.1

.1

.2

 
(.8
)
(.8
)
2.7

2.9

Operating income
3.9

3.1

4.6

3.9

Income from continuing operations
2.7

1.3

4.1

2.1

Income (loss) from discontinued operations, net of tax
—

(.1
)
.5

(.2
)
Earnings
$
2.7

$
1.2

$
4.6

$
1.9


This segment reported third quarter earnings of $2.7 million, compared to earnings of $1.2 million a year ago. The earnings increase largely resulted from lower income taxes.


13


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 September 30, 2014 and 2013:
•
An unrealized gain on commodity derivatives of $18.1 million after tax in 2014, and an unrealized loss on commodity derivatives of $7.9 million after tax in 2013.

Nine Months Ended September 30, 2014 and 2013:
•
An unrealized gain on commodity derivatives of $10.7 million after tax in 2014, and an unrealized loss on commodity derivatives of $3.4 million after tax in 2013.
•
Natural gas gathering asset impairment of $9.0 million after tax in 2013.

Twelve Months Ended September 30, 2014:
•
An unrealized gain on commodity derivatives of $10.1 million after tax.
•
A reversal of an arbitration charge of $1.5 million after tax.

Twelve Months Ended September 30, 2013:
•
Natural gas gathering asset impairment of $9.0 million after tax.
•
An unrealized loss on commodity derivatives of $3.5 million after tax.
•
Write-down of oil and natural gas properties of $145.9 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 plans to market and potentially sell its exploration and production company. While it intends to exit the business, there is no assurance that any transaction will be completed.
•
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.

14


•
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.

15


MDU Resources Group, Inc.
 
 
 
Three Months Ended
Nine Months Ended
 
September 30,
September 30,
 
2014

2013

2014

2013

 
(In millions, except per share amounts)
 
(Unaudited)
Operating revenues
$
1,370.5

$
1,285.8

$
3,507.4

$
3,278.0

Operating expenses:
 
 
 
 
Fuel and purchased power
19.2

20.0

66.8

59.8

Purchased natural gas sold
47.7

35.8

377.0

305.3

Operation and maintenance
977.8

934.3

2,228.1

2,132.5

Depreciation, depletion and amortization
103.5

100.0

306.2

288.8

Taxes, other than income
45.5

45.8

150.7

145.8

 
1,193.7

1,135.9

3,128.8

2,932.2

Operating income
176.8

149.9

378.6

345.8

Loss from equity method investments
(.1
)
(.1
)
(.3
)
(.4
)
Other income
2.6

2.3

7.6

5.0

Interest expense
22.4

21.0

65.0

63.3

Income before income taxes
156.9

131.1

320.9

287.1

Income taxes
54.8

46.5

109.8

99.6

Income from continuing operations
102.1

84.6

211.1

187.5

Income (loss) from discontinued operations, net of tax
—

(.1
)
.5

(.2
)
Net income
102.1

84.5

211.6

187.3

Net loss attributable to noncontrolling interest
(1.1
)
—

(2.4
)
(.2
)
Dividends declared on preferred stocks
.2

.2

.5

.5

Earnings on common stock
$
103.0

$
84.3

$
213.5

$
187.0

 








Earnings per common share – basic:








Earnings before discontinued operations
$
.53

$
.45

$
1.11

$
.99

Discontinued operations, net of tax
—

—

—

—

Earnings per common share – basic
$
.53

$
.45

$
1.11

$
.99

Earnings per common share – diluted:








Earnings before discontinued operations
$
.53

$
.44

$
1.11

$
.99

Discontinued operations, net of tax
—

—

—

—

Earnings per common share – diluted
$
.53

$
.44

$
1.11

$
.99

Dividends declared per common share
$
.1775

$
.1725

$
.5325

$
.5175

Weighted average common shares outstanding – basic
193.9

188.8

192.0

188.8

Weighted average common shares outstanding – diluted
194.3

189.6

192.3

189.6




16




Nine Months Ended

September 30,

2014

 
2013


(Unaudited)
Other Financial Data


 


Book value per common share
$
16.20

 
$
14.49

Market price per common share
$
27.81

 
$
27.97

Dividend yield (indicated annual rate)
2.6
%
 
2.5
%
Price/adjusted earnings ratio*
18.2
x
 
19.3
x
Market value as a percent of book value
171.7
%
 
193.0
%
Net operating cash flow**
$
403

 
$
429

Total assets**
$
7,774

 
$
7,167

Total equity**
$
3,159

 
$
2,750

Total debt **
$
2,211

 
$
2,019

Capitalization ratios: ***


 


Total equity
58.8
%
 
57.7
%
Total debt
41.2

 
42.3


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




17