MDU Resources Reports Second Quarter Earnings, Reaffirms 2013 Earnings Guidance

  • Adjusted earnings per share of 25 cents compared to 17 cents last year, 47 percent increase; GAAP earnings per share of 24 cents compared to 29 cents last year.
  • E&P adjusted earnings improved 66 percent (84 percent on a GAAP basis) with oil production growth of 37 percent.
  • Construction business improves earnings 39 percent and reports higher backlog of $1.2 billion.
  • Natural gas utility sees 14 percent increase in sales; electric utility has 4 percent growth in retail sales.
  • Pipeline and energy services group diesel topping plant construction well underway.

Business Wire

BISMARCK, N.D.--(BUSINESS WIRE)--

MDU Resources Group, Inc. (MDU) today reported second quarter consolidated adjusted earnings of $47.2 million, or 25 cents per share, compared to $32.5 million, or 17 cents per share in the second quarter of 2012. Consolidated GAAP earnings were $46.3 million, or 24 cents per common share, compared to $53.9 million, or 29 cents per common share for the second quarter of 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.

"We had a strong quarter, led by another impressive increase in oil production and strong earnings growth from our construction business," said David L. Goodin, president and CEO of MDU Resources. "Our construction business had their most profitable second quarter since 2008. That and their growing backlog are encouraging signs that a sustained recovery is taking hold in the industry.

"Our exploration and production business has increased its 2013 target to 25 to 35 percent year-over-year growth in oil production," Goodin said. "At midyear, Fidelity has increased oil production 41 percent over the first six months of 2012."

Fidelity's oil production in the Bakken increased by 42 percent in the second quarter, compared to the same period a year ago. Oil production in the increasingly prolific Paradox Basin nearly quadrupled over the same time period.

Earnings at the company's construction business increased 39 percent despite a slow start to the construction season caused by record wet weather in parts of the Midwest. The construction materials and contracting business had improved earnings on lower revenues as a result of margin expansion driven in part by a lower cost structure. Earnings increased in all regions of the construction services business. The combined construction backlog has grown to $1.2 billion, compared to $980 million at the same time in 2012.

The utility business experienced a lower seasonal loss for the quarter compared to last year. Natural gas sales grew 14 percent primarily the result of colder weather along with 4 percent growth in electric retail sales. Customer growth continues strong particularly in the Bakken area with a 7 percent increase in electric customers and 6 percent increase in natural gas customers compared to last year. Earnings on a year-to-date basis are at a record pace totaling $40.8 million.

The pipeline and energy services business benefited from the addition of the Pronghorn natural gas and oil midstream assets acquired in May last year. Recently the business announced plans for a proposed 400-mile natural gas pipeline pending adequate contract commitments. The project would stretch from western North Dakota to western Minnesota to serve markets in eastern North Dakota, Minnesota and Wisconsin, increasing pipeline takeaway capacity out of the Bakken to accommodate rapidly growing natural gas production.

Outside of the Bakken, gathering volumes declined as producers adjusted operations because of low natural gas prices. As a result, the business recorded a $9.0 million (after tax) impairment of coalbed gathering assets.

Construction of the Dakota Prairie diesel topping plant continues on schedule for startup in the fourth quarter of 2014. The project is expected to generate EBITDA of $70 million to $90 million in the first year of operation, to be shared equally with Calumet Specialty Products.

Adjusted earnings for the six months ended June 30 were $107.3 million, or 57 cents per share, compared to $70.8 million, or 37 cents per share a year ago. Consolidated year-to-date GAAP earnings were $102.7 million, or 54 cents per share, compared to $89.6 million, or 47 cents per share for the six months ended June 30, 2012.

The company reaffirmed its 2013 adjusted earnings guidance of $1.30 to $1.40 per share excluding discontinued operations, the unrealized commodity derivatives gain and the natural gas gathering asset impairment. Including these adjustments, 2013 GAAP earnings guidance is in the same range.

"I am encouraged by the growth that is occurring within all of our businesses," Goodin said. "Our year-to-date consolidated earnings per share is substantially higher compared to a year ago. We are in a good position to achieve our earnings target. More importantly, our $850 million investment this year along with our planned future investments, has us well positioned for long-term growth."

The company will host a webcast at 10 a.m. EDT Thursday, Aug. 1 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 13007081.

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.

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.

 

Earnings by Segment

         
Second Quarter Second Quarter
2013 2012
Adjusted Earnings Adjusted Earnings
Business Line     (In Millions)       (In Millions)
Exploration and Production $ 24.8 $ 15.0
Regulated
Electric and natural gas utilities (1.5 ) (2.0 )
Pipeline and energy services 2.6 2.5
Construction Materials and Services 22.9 16.5
Other and eliminations     (1.6 )       .5  
Adjusted earnings     $ 47.2         $ 32.5  
 
       

Reconciliation of GAAP to Adjusted Earnings

 
Second Second YTD YTD
Quarter Quarter

June 30,

June 30,

2013 2012 2013 2012
    Earnings   Earnings   Earnings   Earnings
(In millions, except per share amounts)
Earnings on common stock $ 46.3 $ 53.9 $ 102.7 $ 89.6
Adjustments net of tax:
Discontinued operations .1 (5.1 ) .2 (5.0 )
Unrealized commodity derivatives gain (8.2 ) (3.0 ) (4.6 ) (.5 )
Natural gas gathering asset impairment 9.0 1.7 9.0 1.7
Net benefit related to natural gas gathering operations litigation       (15.0 )       (15.0 )
Adjusted earnings   $ 47.2     $ 32.5     $ 107.3     $ 70.8  
Adjusted earnings per share   $ .25     $ .17     $ .57     $ .37  
 

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

  • Earnings per common share for 2013, diluted, are projected in the range of $1.30 to $1.40 on an adjusted basis excluding discontinued operations, the unrealized commodity derivatives gain and the natural gas gathering asset impairment. Including these adjustments, 2013 GAAP earnings guidance is in the same range. The unrealized commodity derivatives fair value is likely to fluctuate on a quarterly basis, which could cause the GAAP guidance range to change 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 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 will have the construction materials and services business involved in constructing the facility, the exploration and production business supplying production to the plant, the pipeline transporting natural gas to the plant, and the utility supplying electricity.
  • Estimated capital expenditures for 2013 are approximately $850 million, excluding noncontrolling interest capital expenditures related to Dakota Prairie Refining.

Exploration and Production

   
Three Months Ended Six Months Ended
    June 30,   June 30,
    2013     2012     2013     2012  
(Dollars in millions, where applicable)
Operating revenues:    
Oil $ 105.9 $ 70.9 $ 205.9 $ 142.2
Natural gas liquids 6.2 7.1 13.7 16.8
Natural gas 23.2 12.0 42.4 31.5
Realized commodity derivatives gain 1.3 11.1 5.6 14.6
Unrealized commodity derivatives gain   13.0     4.8     7.2     .7  
    149.6     105.9     274.8     205.8  
Operating expenses:
Operation and maintenance:
Lease operating costs 22.0 19.0 42.8 37.5
Gathering and transportation 4.2 4.2 8.5 8.5
Other 10.3 9.5 20.4 18.7
Depreciation, depletion and amortization 45.1 34.4 88.3 71.2
Taxes, other than income:
Production and property taxes 12.3 8.7 23.9 18.3
Other   .3     .3     .6     .6  
    94.2     76.1     184.5     154.8  
Operating income   55.4     29.8     90.3     51.0  
Earnings   $ 33.0     $ 18.0     $ 53.3     $ 30.9  
Unrealized commodity derivatives gain   (8.2 )   (3.0 )   (4.6 )   (.5 )
Adjusted earnings   $ 24.8     $ 15.0     $ 48.7     $ 30.4  
Production:
Oil (MBbls) 1,201 876 2,319 1,643
Natural gas liquids (MBbls) 191 209 392 399
Natural gas (MMcf) 6,987 8,239 13,700 18,286
Total production (MBOE) 2,557 2,458 4,995 5,090
Average realized prices (excluding realized and unrealized commodity derivatives gain):
Oil (per barrel) $ 88.12 $ 80.99 $ 88.75 $ 86.60
Natural gas liquids (per barrel) $ 32.26 $ 33.77 $ 34.86 $ 41.91
Natural gas (per Mcf) $ 3.33 $ 1.46 $ 3.10 $ 1.72
Average realized prices (including realized commodity derivatives gain):
Oil (per barrel) $ 90.55 $ 83.06 $ 91.18 $ 85.73
Natural gas liquids (per barrel) $ 32.26 $ 33.77 $ 34.86 $ 41.91
Natural gas (per Mcf) $ 3.09 $ 2.59 $ 3.09 $ 2.60
Average depreciation, depletion and amortization rate, per BOE $ 16.90 $ 13.32 $ 16.90 $ 13.32
Production costs, including taxes, per BOE:
Lease operating costs $ 8.59 $ 7.74 $ 8.57 $ 7.37
Gathering and transportation 1.66 1.70 1.71 1.66
Production and property taxes   4.81     3.54     4.78     3.58  
    $ 15.06     $ 12.98     $ 15.06     $ 12.61  
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.
 

Second quarter adjusted earnings at this segment were $24.8 million in 2013, compared to $15.0 million in 2012. This increase reflects increased oil production of 37 percent and higher average realized natural gas and oil prices (excluding commodity derivatives gain) of 128 percent and 9 percent, respectively. Partially offsetting the earnings increase was higher depreciation, depletion and amortization expense, a lower realized commodity derivatives gain, decreased natural gas production of 15 percent, higher production taxes and higher lease operating expenses. GAAP earnings were $33.0 million in second quarter 2013 compared to $18.0 million in the same period last year.

Effective April 1, the company elected to discontinue hedge accounting for all of its commodity derivative instruments and, therefore, all prospective changes in the fair value of the company's commodity derivative instruments are recorded in the income statement.

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

  • The company expects to spend approximately $400 million in capital expenditures in 2013. With improving well cost efficiencies and having essentially completed the extensive 2012 exploration program, the capital program will focus on growth projects where the company expects higher returns, namely the Bakken, Paradox Basin and Texas, as described below. The 2013 planned capital expenditure total does not include potential acquisitions.
  • For 2013, the company expects a 25 to 35 percent increase in oil production, a flat to slight decrease in natural gas liquids production, and a 15 to 25 percent decrease in natural gas production. The 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, Paradox and Texas areas.
  • Bakken areas
    • The company owns a total of approximately 127,000 net acres of leaseholds in Mountrail, Stark and Richland counties.
    • Capital expenditures are expected to total approximately $200 million in 2013. During second quarter the company operated three rigs in the play and as drilling efficiencies have accelerated, two rigs are now being utilized.
    • Net oil production for second quarter was more than 7,500 barrels of oil per day.
    • In mid-July the first three-well pad in Mountrail county began producing. In the first 10 days of production, the pad averaged 2,770 BOPD gross, 1,160 BOPD net. The potential exists for 10 additional multi-well pads in Mountrail county.
  • Paradox Basin, Utah
    • The company has approximately 92,000 net acres and also has an option to lease another 20,000 acres.
    • Capital expenditures are expected to total $80 million in 2013. The company expects to operate one rig throughout the year.
    • Net oil production for second quarter was approximately 2,300 BOPD, up 44 percent from first quarter.
    • Following nine months of flowing at a constant 1,500 BOPD gross, the Cane Creek Unit 12-1 well recently came off its plateau rate and is still flowing at 1,100 BOPD. The well has flowed over 400 MBO on a cumulative basis and has a forecasted EUR of 1.2 to 1.4 MMBO. This well is amongst the best onshore oil wells drilled in the U.S. last year.
    • The last three wells drilled are the CCU 18-1, CCU 13-1 and the CCU 17-1. The respective gross consistent flowing rates are 900 BOPD, 700 BOPD and 500 BOPD. Respective EURs are forecast at 500 to 700 MBO, 400 to 600 MBO and 400 to 600 MBO.
    • The company's understanding of this play and the quality of the play continues to improve. Accelerated development of the play will be largely dependent upon receiving sufficient permits to sustain a multi-rig program. It is anticipated that this field will play a key role in the company's oil growth strategy.
  • Texas
    • The company is targeting areas that have the potential for higher liquids content with approximately $35 million of capital planned for this year.
  • Other opportunities
    • Upon evaluation of wells drilled by the company in Sioux County, Neb., the decision was made to decline an option to purchase acreage in the area at this time.
    • The remaining forecasted 2013 capital has been allocated to other operated and non-operated opportunities.
  • Earnings guidance reflects estimated average NYMEX index prices for August through December in the range of $90 to $100 per barrel of crude oil, and $3.50 to $4.00 per Mcf of natural gas. Estimated prices for natural gas liquids are in the range of $30 to $45 per barrel.
  • For the last six months of 2013, the company has derivative instruments for 11,000 BOPD utilizing swaps and costless collars with a weighted average price of $97.76 and $92.50/$107.03 (floor/ceiling) respectively, and 50,000 MMBtu of natural gas per day, with an additional 10,000 MMBtu per day for September through December, utilizing swaps at a weighted average price of $3.78.
  • For the first six months of 2014, the company has derivative instruments for 8,000 BOPD, and 2,000 BOPD for July through December, utilizing swaps with a weighted average price of $93.43, and for 2014 the company has derivative instruments for 20,000 MMBtu of natural gas per day utilizing swaps at a weighted average price of $4.13.
  • For 2015, the company has a derivative instrument for 10,000 MMBtu of natural gas per day utilizing a swap at $4.2825.
  • The commodity derivative instruments that are in place as of July 31 are summarized in the following chart:
                               
                Forward    
Notional
Period Volume Price
Commodity     Type     Index     Outstanding     (Bbl/MMBtu)     (Per Bbl/MMBtu)
Crude Oil Collar NYMEX 7/13 - 12/13 184,000 $95.00-$117.00
Crude Oil Collar NYMEX 7/13 - 12/13 184,000 $90.00-$97.05
Crude Oil Swap NYMEX 7/13 - 12/13 92,000 $95.00
Crude Oil Swap NYMEX 7/13 - 12/13 92,000 $95.30
Crude Oil Swap NYMEX 7/13 - 12/13 92,000 $100.00
Crude Oil Swap NYMEX 7/13 - 12/13 92,000 $100.02
Crude Oil Swap NYMEX 7/13 - 12/13 184,000 $102.00
Crude Oil Swap NYMEX 7/13 - 12/13 184,000 $104.00
Crude Oil Swap NYMEX 7/13 - 12/13 184,000 $98.00
Crude Oil Swap NYMEX 7/13 - 12/13 92,000 $94.15
Crude Oil Swap NYMEX 7/13 - 12/13 92,000 $94.00
Crude Oil Swap NYMEX 7/13 - 12/13 184,000 $97.45
Crude Oil Swap NYMEX 7/13 - 12/13 184,000 $94.15
Crude Oil Swap NYMEX 7/13 - 12/13 184,000 $95.00
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 - 12/14 365,000 $94.05
Crude Oil Swap NYMEX 1/14 - 12/14 365,000 $95.00
Natural Gas Swap NYMEX 7/13 - 12/13 1,840,000 $3.76
Natural Gas Swap NYMEX 7/13 - 12/13 1,840,000 $3.90
Natural Gas Swap NYMEX 7/13 - 12/13 1,840,000 $4.00
Natural Gas Swap NYMEX 7/13 - 12/13 3,680,000 $3.50
Natural Gas Swap NYMEX 9/13 - 12/14 4,870,000 $4.13
Natural Gas Swap NYMEX 1/14 - 12/14 3,650,000 $4.13
Natural Gas     Swap     NYMEX     1/15 - 12/15     3,650,000     $4.2825
 

Regulated

Electric and Natural Gas Utilities

Electric    
Three Months Ended Six Months Ended
    June 30,   June 30,
    2013     2012     2013     2012  
(Dollars in millions, where applicable)
Operating revenues   $ 57.0     $ 53.0     $ 121.6     $ 110.9  
Operating expenses:    
Fuel and purchased power 18.2 15.2 39.8 33.6
Operation and maintenance 20.5 19.1 36.8 35.3
Depreciation, depletion and amortization 7.9 8.0 16.5 16.1
Taxes, other than income   2.8     2.6     5.7     5.3  
    49.4     44.9     98.8     90.3  
Operating income   7.6     8.1     22.8     20.6  
Earnings   $ 4.4     $ 4.4     $ 14.2     $ 12.0  
Retail sales (million kWh) 691.5 666.3 1,534.1 1,436.0
Sales for resale (million kWh) 8.8 1.0 16.2 2.9
Average cost of fuel and purchased power per kWh   $ .024     $ .021     $ .024     $ .022  
 
Natural Gas Distribution
Three Months Ended Six Months Ended
    June 30,   June 30,
    2013     2012     2013     2012  
(Dollars in millions)
Operating revenues   $ 127.6     $ 116.8     $ 459.3     $ 424.7  
Operating expenses:
Purchased natural gas sold 73.5 62.9 286.9 262.2
Operation and maintenance 35.7 35.9 69.9 71.1
Depreciation, depletion and amortization 12.4 11.3 24.5 22.5
Taxes, other than income   9.5     10.0     25.7     26.2  
    131.1     120.1     407.0     382.0  
Operating income (loss)   (3.5 )   (3.3 )   52.3     42.7  
Earnings (loss)   $ (5.9 )   $ (6.4 )   $ 26.6     $ 19.1  
Volumes (MMdk):
Sales 15.3 13.4 60.2 52.1
Transportation   30.3     26.8     68.5     64.7  
Total throughput   45.6     40.2     128.7     116.8  
Degree days (% of normal)*
Montana-Dakota/Great Plains 130 % 77 % 104 % 77 %
Cascade 82 % 94 % 93 % 99 %
Intermountain   99 %   97 %   110 %   94 %
* Degree days are a measure of the daily temperature-related demand for energy for heating.
 

The combined utility businesses reported a seasonal loss of $1.5 million in the second quarter of 2013, compared to a loss of $2.0 million for the same period in 2012. This improvement reflects increased natural gas retail sales volumes resulting from colder weather than last year, as well as higher electric retail sales volumes. Partially offsetting the decreased loss was higher operations and maintenance expense and higher depreciation, depletion and amortization expense.

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

  • The company filed an application June 14 for an advance determination of prudence with the North Dakota Public Service Commission to add pollution control equipment at the Lewis & Clark generating station to comply with the Mercury and Air Toxics Standards rules, projected to be completed in 2016. Project cost is estimated to be $26.1 million.
  • The company filed an application Dec. 21 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, the landfill gas production facility, an operations building, automated meter reading and new customer billing system. The company implemented the full request July 22, subject to refund. A hearing is scheduled for Oct. 29.
  • The company filed an application Sept. 26 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, the landfill gas production facility, a region operations building, automated meter reading and new customer billing system. The company requested an interim increase of $1.7 million or approximately 2.9 percent. The commission granted an interim increase of approximately $850,000 annually, effective April 15. A hearing is scheduled for Aug. 5.
  • The EPA approved the South Dakota Regional Haze Program, which requires the Big Stone Station to install and operate a best-available retrofit technology air-quality control system to reduce emissions of particulate matter, sulfur dioxide and nitrogen oxides. The company's share of the cost for the installation is estimated at $100 million and is expected to be complete in 2015. The NDPSC has approved advance determination of prudence for recovery of costs related to this system in electric rates charged to customers. The company filed an application Feb. 11 with the NDPSC for approval of an environmental cost recovery rider related to costs for the required environmental retrofit at the Big Stone Station. A hearing is scheduled for Sept. 16.
  • The company plans to construct and operate an 88-megawatt simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $86 million and a projected in-service date in third quarter 2014. It will be located on owned property that is 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 the NDPSC.
  • Planned investments are approximately $75 million for 2013 to serve the growing electric and natural gas customer base associated with the Bakken oil development in western North Dakota and eastern Montana.
  • Rate base growth is projected to be approximately 6 percent compounded annually over the next five years.
  • 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 natural gas line project into the Hanford Nuclear Site in Washington.
  • 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.
  • Opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted toward delivery of energy to major market areas are being pursued.
     
Pipeline and Energy Services
Three Months Ended Six Months Ended
    June 30,     June 30,  
    2013       2012       2013       2012    
(Dollars in millions)
Operating revenues   $ 50.9       $ 43.6       $ 97.3       $ 93.2    
Operating expenses:  
Purchased natural gas sold 15.8 8.5 28.6 24.6
Operation and maintenance 32.1 * (1.4 ) ** 49.3 * 15.6 **
Depreciation, depletion and amortization 7.7 6.8 14.9 13.1
Taxes, other than income   3.5       3.5       6.9       6.9    
    59.1       17.4       99.7       60.2    
Operating income (loss)   (8.2 )     26.2       (2.4 )     33.0    
Earnings (loss)   $ (6.4 ) *   $ 15.8   **   $ (4.1 ) *   $ 18.6   **
Natural gas gathering asset impairment 9.0 1.7 9.0 1.7
Net benefit related to natural gas gathering operations litigation         (15.0 )           (15.0 )  
Adjusted earnings   $ 2.6       $ 2.5       $ 4.9       $ 5.3    
Transportation volumes (MMdk) 40.3 36.8 77.1 68.8
Natural gas gathering volumes (MMdk) 10.0 11.6 19.9 25.8
Customer natural gas storage balance (MMdk):
Beginning of period 24.7 27.3 43.7 36.0
Net injection (withdrawal)   .5       13.1       (18.5 )     4.4    
End of period   25.2       40.4       25.2       40.4    
* Reflects an impairment of coalbed natural gas gathering assets of $14.5 million ($9.0 million after tax).
** Reflects a net benefit of $24.1 million ($15.0 million after tax) related to natural gas gathering operations litigation, largely reflected in O&M expense, as well as an impairment of coalbed natural gas gathering assets of $2.7 million ($1.7 million after tax).
 

This segment reported second quarter adjusted earnings of $2.6 million, compared to $2.5 million in 2012. The earnings improvement resulted from higher revenues from a May 2012 acquisition and lower operations and maintenance expense largely offset by lower storage services revenue. On a GAAP basis, this segment had a loss of $6.4 million in second quarter 2013 compared to earnings of $15.8 million for the same period in 2012.

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., has 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 will process Bakken crude and market the diesel within the Bakken region. Total project costs are estimated to be approximately $300 million, with a projected in-service date in late 2014.
  • In May 2012 the company purchased a 50 percent undivided interest in Whiting Oil and Gas Corp.'s Pronghorn natural gas and oil midstream assets near Belfield, N.D., in the Bakken area. The company invested approximately $100 million in 2012 including the purchase price. The Belfield natural gas processing plant has an inlet processing capacity of 35 million cubic feet per day. The company will receive a full year of benefit from this acquisition in 2013.
  • Last August the company placed in service approximately 13 miles of high-pressure transmission pipeline from the Stateline processing facilities in northwestern North Dakota to deliver natural gas into the Northern Border Pipeline, which is expected to result in increased transportation volumes for 2013.
  • Dry natural gas gathering volumes are expected to be lower in 2013 compared to 2012 because of curtailments and the deferral of development activity by producers.
  • The company has an agreement to construct a pipeline in 2014 to connect the planned Garden Creek II gas processing plant in northwestern North Dakota to deliver natural gas into the Northern Border Pipeline.
  • In May the company announced plans for a proposed natural gas pipeline from far western North Dakota to western Minnesota to transport natural gas to markets in eastern North Dakota, Minnesota and Wisconsin. The pipeline would initially 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 $650 million to $700 million. Long-term capacity commitments on the proposed pipeline will be sought during an open season expected to begin this fall. Following receipt of adequate capacity commitments and necessary permits and regulatory approvals, construction on the new pipeline would begin in early 2016 with completion expected by late 2016.
  • The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Montana, North Dakota and Wyoming, is expanding, most notably the Bakken area of North Dakota and eastern Montana. The company owns an extensive natural gas pipeline system in the Bakken area. Ongoing energy development is expected to have many direct and indirect benefits to this business.

Construction

 
Construction Materials and Contracting
  Three Months Ended   Six Months Ended
    June 30,   June 30,
    2013     2012     2013     2012  
(Dollars in millions)
Operating revenues   $ 431.3     $ 442.1     $ 597.6     $ 591.5  
Operating expenses:      
Operation and maintenance 381.2 396.7 547.9 553.7
Depreciation, depletion and amortization 18.7 19.8 37.7 39.6
Taxes, other than income   10.6     10.6     19.1     18.6  
    410.5     427.1     604.7     611.9  
Operating income (loss)   20.8     15.0     (7.1 )   (20.4 )
Earnings (loss)   $ 10.0     $ 7.8     $ (10.5 )   $ (17.1 )
Sales (000's):
Aggregates (tons) 6,152 6,481 9,110 8,974
Asphalt (tons) 1,518 1,761 1,667 1,861
Ready-mixed concrete (cubic yards)   846     837     1,326     1,305  
 
       
Construction Services
Three Months Ended Six Months Ended
    June 30,   June 30,
    2013     2012     2013     2012
(In millions)
Operating revenues   $ 279.6     $ 224.1     $ 511.0     $ 442.3
Operating expenses:    
Operation and maintenance 245.9 198.6 444.3 386.6
Depreciation, depletion and amortization 3.0 2.8 6.0 5.5
Taxes, other than income   8.4     7.2     18.0     15.0
    257.3     208.6     468.3     407.1
Operating income   22.3     15.5     42.7     35.2
Earnings   $ 12.9     $ 8.7     $ 24.6     $ 20.1
 

The combined construction businesses reported second quarter earnings of $22.9 million, compared to earnings of $16.5 million a year ago. The earnings increase reflects higher workloads and margins at the services group, and higher asphalt, liquid asphalt oil and ready-mixed concrete margins partially offset by lower 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 June 30 was $730 million, compared to $636 million a year ago. Private work represents 13 percent of construction backlog, up from 8 percent a year ago. Public work represents 87 percent of backlog. The June 30 approximate backlog at construction services was $447 million, compared to $344 million a year ago. The backlogs include a variety of projects such as highway paving projects, airports, bridge work, reclamation, harbor expansions, substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.
  • The company's approximate backlog in North Dakota was $165 million, compared to $86 million a year ago.
  • Projected revenues included in the company's 2013 earnings guidance are in the range of $1.6 billion to $1.7 billion for construction materials and $1.0 billion to $1.1 billion for construction services.
  • The company anticipates margins in 2013 to be higher than 2012.
  • 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 Six Months Ended
    June 30,   June 30,
    2013     2012     2013     2012
(In millions)
Operating revenues   $ 2.3     $ 2.5     $ 4.5     $ 4.6
Operating expenses:    
Operation and maintenance 1.4 1.5 2.7 2.9
Depreciation, depletion and amortization .5 .5 1.0 1.0
Taxes, other than income       .1     .1    
    1.9     2.1     3.8     3.9
Operating income   .4     .4     .7     .7
Income from continuing operations .5 .5 .9 1.0
Income (loss) from discontinued operations, net of tax   (.1 )   5.1     (.2 )   5.0
Earnings   $ .4     $ 5.6     $ .7     $ 6.0
 

Second quarter earnings were $400,000 compared to $5.6 million in 2012. Income from discontinued operations in 2012 reflects a net benefit largely resulting from estimated insurance recoveries associated with a construction contract at the domestic power production business, which was sold in 2007.

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 second quarter unrealized commodity derivatives gain of $8.2 million after tax in 2013, and $3.0 million after tax in 2012, adjustments to exclude second quarter natural gas gathering asset impairments of $9.0 million after tax in 2013, and $1.7 million after tax in 2012, an adjustment to exclude a second quarter 2012 reversal of an arbitration charge of $15.0 million after tax, as well as adjustments to exclude year-to-date unrealized commodity derivatives gain of $4.6 million after tax in 2013, and $500,000 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 the diesel topping plant 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, and revenues and cash flows.
  • Competition is increasing in all of the company’s businesses.
  • The company could be subject to limitations on its ability to pay dividends.
  • An increase in costs related to obligations under multiemployer pension plans could have a material negative effect on the company’s results of operations and cash flows.
  • The company's operations may be negatively impacted by cyber attacks or acts of terrorism.
  • Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include:
    • Acquisition, disposal and impairments of assets or facilities.
    • Changes in operation, performance and construction of plant facilities or other assets.
    • Changes in present or prospective generation.
    • The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings.
    • The availability of economic expansion or development opportunities.
    • Population growth rates and demographic patterns.
    • Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services.
    • The cyclical nature of large construction projects at certain operations.
    • Changes in tax rates or policies.
    • Unanticipated project delays or changes in project costs, including related energy costs.
    • Unanticipated changes in operating expenses or capital expenditures.
    • Labor negotiations or disputes.
    • Inability of the various contract counterparties to meet their contractual obligations.
    • Changes in accounting principles and/or the application of such principles to the company.
    • Changes in technology.
    • Changes in legal or regulatory proceedings.
    • The ability to effectively integrate the operations and the internal controls of acquired companies.
    • The ability to attract and retain skilled labor and key personnel.
    • Increases in employee and retiree benefit costs and funding requirements.

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

MDU Resources Group, Inc.
  Three Months Ended   Six Months Ended
    June 30,   June 30,
    2013     2012     2013     2012
(In millions, except per share amounts)
(Unaudited)
Operating revenues   $ 1,060.6     $ 968.0     $ 1,992.2     $ 1,820.8
Operating expenses:    
Fuel and purchased power 18.2 15.2 39.8 33.6
Purchased natural gas sold 70.2 58.4 269.4 243.9
Operation and maintenance 738.1 676.1 1,198.2 1,120.6
Depreciation, depletion and amortization 95.3 83.6 188.9 169.0
Taxes, other than income   47.4     43.0     100.0     90.9
    969.2     876.3     1,796.3     1,658.0
Operating income 91.4 91.7 195.9 162.8
Earnings (loss) from equity method investments .4 (.3 ) 1.6
Other income 1.4 1.2 2.7 2.4
Interest expense   21.4     17.6     42.3     37.1
Income before income taxes 71.4 75.7 156.0 129.7
Income taxes   25.0     26.7     53.0     44.8
Income from continuing operations 46.4 49.0 103.0 84.9
Income (loss) from discontinued operations, net of tax   (.1 )   5.1     (.2 )   5.0
Net income 46.3 54.1 102.8 89.9
Net loss attributable to noncontrolling interest (.2 ) (.2 )
Dividends declared on preferred stocks   .2     .2     .3     .3
Earnings on common stock   $ 46.3     $ 53.9     $ 102.7     $ 89.6
 
Earnings per common share – basic:
Earnings before discontinued operations $ .25 $ .26 $ .54 $ .45
Discontinued operations, net of tax       .03         .02
Earnings per common share – basic   $ .25     $ .29     $ .54     $ .47
Earnings per common share – diluted:
Earnings before discontinued operations $ .24 $ .26 $ .54 $ .45
Discontinued operations, net of tax       .03         .02
Earnings per common share – diluted   $ .24     $ .29     $ .54     $ .47
Dividends declared per common share   $ .1725     $ .1675     $ .3450     $ .3350
Weighted average common shares outstanding – basic   188.8     188.8     188.8     188.8
Weighted average common shares outstanding – diluted   189.5     189.1     189.5     189.1
 
     

 

Six Months Ended
June 30,
2013       2012
(Unaudited)
 
Other Financial Data
Book value per common share $ 14.19 $ 14.86
Market price per common share $ 25.91 $ 21.61
Dividend yield (indicated annual rate) 2.7 % 3.1 %
Price/earnings ratio*

***

19.1

x

Market value as a percent of book value 182.6 % 145.4 %
Net operating cash flow** $ 234 $ 175
Total assets** $ 7,092 $ 6,902
Total equity** $ 2,695 $ 2,820
Total debt ** $ 2,038 $ 1,666
Capitalization ratios:
Total equity 57 % 63 %
Total debt 43   37  
100 % 100 %
 
* Represents 12 months ended
** In millions
*** Not meaningful because of effects of 2012 noncash write-downs of $246.8 million after tax
 

Contact:
MDU Resources Group, Inc.
Financial:
Phyllis A. Rittenbach, 701-530-1057
Director - Investor Relations
or
Media:
Rick Matteson, 701-530-1700
Director of Communications and Public Affairs
or
Laura Lueder, 701-530-1095
Corporate Public Relations Manager

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