MDU Resources Reports Third Quarter Earnings, Increases 2013 Earnings Guidance

MDU Resources Group, Inc. (NYSE:MDU) today reported third quarter consolidated adjusted earnings of $92.3 million, or 49 cents per share, compared to $71.9 million, or 38 cents per share in the third quarter of 2012. Consolidated GAAP earnings were $84.3 million, or 44 cents per common share, compared to a loss of $29.8 million, or 16 cents per common share for the third 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 are seeing excellent results from our businesses' capital investments and strategic focus continuing the trend we have had for the last three quarters," said David L. Goodin, president and CEO of MDU Resources. "Our strong operations have produced 38 percent growth year-to-date in consolidated adjusted earnings per share compared to last year. These results reflect the value of our diversified model with all of our business segments contributing to this success.

"Our exploration and production business continued to outperform its year-over-year production target. Fidelity increased third-quarter oil production by 37 percent from the same period last year, and is well positioned to deliver on its annual growth target of 30 to 35 percent."

Fidelity's success with improved completion techniques in the Bakken helped increase oil production in that play by 41 percent in the third quarter. While the Bakken continues to be the largest source of Fidelity's production, the Paradox Basin is becoming an increasingly important part of the company's production mix and growth platform. Fidelity's latest Paradox well, the Cane Creek Unit 36-1, has been flowing consistently above 1,250 barrels per day since Oct. 11 with a flowing pressure of approximately 3,400 psi.

The construction materials and services businesses sustained its growth in volumes and margins with combined earnings of $61.4 million, compared to $51.8 million last year. The construction materials group had it's best quarter since 2007. On a combined basis, the construction businesses' earnings are 29 percent higher for the trailing twelve months ended Sept. 30, compared to 2012 annual earnings. Combined backlog increased to $958 million compared to $834 million a year ago. This includes the largest road construction contract ever awarded to Knife River -- a $55 million project in western North Dakota. Knife River began work on that project in September.

The pipeline and energy services business increased earnings to $5.3 million, $2.0 million higher than third quarter of last year, largely on the strength of its investment in the Pronghorn natural gas and oil midstream assets in May 2012 and lower operation and maintenance expense. Construction of a diesel topping plant near Dickinson, N.D. in the Bakken area is progressing on schedule with expected completion in late 2014.

The pipeline group continues to evaluate routes for a 400-mile natural gas pipeline that it plans to build from western North Dakota to western Minnesota. The alternate routes being evaluated would give customers access to broader market diversity, in addition to serving industrial load in eastern North Dakota. Once built, the pipeline would provide much-needed takeaway capacity for the Bakken's rapidly growing natural gas production, which in August reached a milestone of 1 billion cubic feet per day. In addition, on Oct. 31, WBI Energy Transmission filed a rate increase request with the Federal Energy Regulatory Commission for an increase of $28.9 million annually to cover increased investments of $312 million, increased operating costs, and the effects of lower storage and off system volumes. This is the first case the company has filed in approximately 14 years.

The electric utility business increased earnings to $11.4 million as it continued to experience growth in customers and electricity sales related to Bakken production activity and the ancillary businesses attracted by Bakken oil development. The natural gas business experienced a normal seasonal loss of $11.2 million. The loss was larger than last year principally because of higher operation and maintenance expense, the result of higher payroll related to employee additions to further support customer growth and pipeline safety.

Adjusted consolidated earnings for the nine months ended Sept. 30 were $199.6 million, or $1.05 per share, compared to $142.7 million, or 76 cents per share a year ago. Consolidated year-to-date GAAP earnings were $187.0 million, or 99 cents per share, compared to $59.7 million, or 32 cents per share for the nine months ended Sept. 30, 2012.

"The focus that our businesses have placed on growth is producing strong results, and I'm pleased with our progress through the first nine months of the year," Goodin said. "Considering earnings to this point, we are increasing our adjusted earnings per share guidance range for 2013 to $1.35 to $1.45. Where we end the year will be dependent on several factors - commodity prices being one. We have seen a widening of differentials for oil and weather is certainly a factor for our construction businesses as to whether we can continue work in our northern tier states in this fourth quarter."

The company will host a webcast at 10 a.m. EDT Friday, Nov. 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 74400416.

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
       
 
Third Third YTD YTD
Quarter Quarter Sept. 30, Sept. 30,
2013 2012 2013 2012
Adjusted Adjusted Adjusted Adjusted
Business Line   Earnings   Earnings   Earnings   Earnings
(In millions)
Exploration and Production $ 25.3 $ 13.8 $ 74.1

$
44.2
Regulated
Electric and natural gas utilities .2 2.2 41.1 33.3
Pipeline and energy services 5.3 3.3 10.3 8.6
Construction Materials and Services 61.4 51.8 75.3 54.7
Other and eliminations   .1   .8     (1.2 )     1.9  
Adjusted earnings   $ 92.3   $ 71.9     $ 199.6    

$
142.7  
 

Reconciliation of GAAP to Adjusted Earnings
 
Third Third YTD YTD
Quarter Quarter Sept. 30, Sept. 30,
2013 2012 2013 2012
    Earnings   Earnings   Earnings   Earnings
(In millions, except per share amounts)
Earnings (loss) on common stock $ 84.3

$
(29.8 )

$
187.0

$
59.7
Adjustments net of tax:
Discontinued operations .1 .1 .2 (4.8 )
Unrealized commodity derivatives loss 7.9 .7 3.4 .2
Natural gas gathering asset impairment 9.0 1.7
Net benefit related to natural gas gathering operations litigation (15.0 )
Write-down of oil and natural gas properties       100.9             100.9  
Adjusted earnings   $ 92.3  

$
71.9    

$
199.6    

$
142.7  
Adjusted earnings per share   $ .49  

$
.38    

$
1.05    

$
.76  
 

On a consolidated basis, the following information highlights the key growth strategies, projections and certain assumptions for the company:
  • Adjusted earnings per common share for 2013 are projected in the range of $1.35 to $1.45, an increase from prior guidance of $1.30 to $1.40. GAAP earnings guidance for 2013 is in the range of $1.30 to $1.40 per share. 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 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, either directly or in kind, to the plant, the pipeline transporting natural gas to the plant, and the utility supplying electricity.
  • Estimated capital expenditures for 2013 are approximately $820 million, including approximately $30 million in proceeds from the sale of non-strategic assets at the exploration and production business. Capital expenditure projections exclude noncontrolling interest capital expenditures related to Dakota Prairie Refining.

Exploration and Production
   
Three Months Ended Nine Months Ended
    September 30,   September 30,
    2013   2012   2013   2012
(Dollars in millions, where applicable)
Operating revenues:    
Oil $ 121.4 $ 75.1 $ 327.3 $ 217.4
Natural gas liquids 7.6 7.9 21.3 24.6
Natural gas 20.1 16.7 62.5 48.1
Realized commodity derivatives gain (loss) (6.6 ) 10.0 (1.0 ) 24.6
Unrealized commodity derivatives loss   (12.6 )   (1.2 )   (5.4 )   (.5 )
    129.9     108.5     404.7     314.2  
Operating expenses:
Operation and maintenance:
Lease operating costs 20.6 20.7 63.4 58.2
Gathering and transportation 3.5 4.3 12.1 12.8
Other 12.5 9.6 32.9 28.4
Depreciation, depletion and amortization 49.6 41.4 137.8 112.6
Taxes, other than income:
Production and property taxes 13.3 9.6 37.1 27.8
Other .2 .2 .9 .8
Write-down of oil and natural gas properties       160.1         160.1  
    99.7     245.9     284.2     400.7  
Operating income (loss)   30.2     (137.4 )   120.5     (86.5 )
Earnings (loss)   $ 17.4     $ (87.8 )   $ 70.7     $ (56.9 )
Unrealized commodity derivatives loss 7.9 .7 3.4 .2
Write-down of oil and natural gas properties       100.9         100.9  
Adjusted earnings   $ 25.3     $ 13.8     $ 74.1     $ 44.2  
Production:
Oil (MBbls) 1,252 912 3,571 2,555
Natural gas liquids (MBbls) 196 211 588 610
Natural gas (MMcf) 7,302 7,390 21,002 25,676
Total Production (MBOE) 2,664 2,354 7,659 7,444
Average realized prices (excluding realized and unrealized commodity derivatives gain/loss):
Oil (per barrel) $ 97.00 $ 82.37 $ 91.64 $ 85.09
Natural gas liquids (per barrel) $ 39.02 $ 37.32 $ 36.24 $ 40.32
Natural gas (per Mcf) $ 2.75 $ 2.25 $ 2.98 $ 1.88
Average realized prices (including realized commodity derivatives gain/loss):
Oil (per barrel) $ 91.03 $ 85.61 $ 91.13 $ 85.69
Natural gas liquids (per barrel) $ 39.02 $ 37.32 $ 36.24 $ 40.32
Natural gas (per Mcf) $ 2.87 $ 3.20 $ 3.02 $ 2.77
Average depreciation, depletion and amortization rate, per BOE $ 17.90 $ 16.85 $ 17.25 $ 14.44
Production costs, including taxes, per BOE:
Lease operating costs $ 7.74 $ 8.77 $ 8.28 $ 7.81
Gathering and transportation 1.33 1.84 1.58 1.72
Production and property taxes   4.98     4.07     4.85     3.74  
    $ 14.05     $ 14.68     $ 14.71     $ 13.27  
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.
 

Third quarter adjusted earnings at this segment were $25.3 million in 2013, compared to $13.8 million in 2012. This increase reflects increased oil production of 37 percent. Higher average realized oil and natural gas prices were largely offset by a net reduction in realized commodity derivatives. Partially offsetting the earnings increase were higher depreciation, depletion and amortization expense and higher production taxes. GAAP earnings were $17.4 million in third quarter 2013 compared to a loss of $87.8 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. The 2013 planned capital expenditure total does not include potential acquisitions nor proceeds from closed divestitures of non-strategic assets of approximately $30 million.
  • For 2013, the company expects a 30 to 35 percent increase in oil production. Noting the level of production reported for the fourth quarter 2012 (59 percent higher than fourth quarter 2011), the company anticipates fourth quarter 2013 production growth of 10 to 15 percent over last year.
  • The company expects a slight decrease in natural gas liquids production and a 15 to 20 percent decrease in natural gas production for 2013 compared to a year ago. The vast majority of the capital program is focused on growing oil production considering current relative commodity prices. The company expects to return to some natural gas development when the commodity prices make it more profitable to do so.
  • During the third quarter, the company had 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 $210 million in 2013. Two rigs are in operation.
    • Net oil production for third quarter was approximately 8,300 barrels of oil per day.
  • Paradox Basin, Utah
    • The company has approximately 92,000 net acres and also has an option to earn another 20,000 acres.
    • Capital expenditures are expected to total $80 million in 2013. The company is operating one rig in the area and expects to add a second rig within the next two to three months.
    • Following nine months of flowing at a constant 1,500 BOPD gross, the Cane Creek Unit 12-1 well came off its plateau rate and is still flowing at approximately 1,000 BOPD.
    • Net oil production for third quarter was approximately 2,300 BOPD, up 272 percent from third quarter 2012 and consistent with second quarter 2013. Well down time, delayed completion activity, and the CCU 12-1 coming off of plateau limited growth in the third quarter. Current production is approximately 3,000 BOPD.
    • The latest well completed was the CCU 36-1, which has been flowing consistently above 1,250 BOPD since Oct. 11 with a flowing pressure of approximately 3,400 psi.
    • 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 $40 million of capital planned for this year.
  • Other opportunities
    • The remaining forecasted 2013 capital has been allocated to other operated and non-operated opportunities.
  • Earnings guidance reflects estimated average NYMEX index prices for November and December in the range of $95 to $105 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 $35 to $50 per barrel.
  • For the last three 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 60,000 MMBtu of natural gas per day utilizing swaps at a weighted average price of $3.80.
  • For the first six months of 2014, the company has derivative instruments for 11,000 BOPD, and 5,000 BOPD for July through December, utilizing swaps with a weighted average price of $94.74, 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 Oct. 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 10/13 - 12/13 92,000 $95.00-$117.00
Crude Oil Collar NYMEX 10/13 - 12/13 92,000 $90.00-$97.05
Crude Oil Swap NYMEX 10/13 - 12/13 46,000 $95.00
Crude Oil Swap NYMEX 10/13 - 12/13 46,000 $95.30
Crude Oil Swap NYMEX 10/13 - 12/13 46,000 $100.00
Crude Oil Swap NYMEX 10/13 - 12/13 46,000 $100.02
Crude Oil Swap NYMEX 10/13 - 12/13 92,000 $102.00
Crude Oil Swap NYMEX 10/13 - 12/13 92,000 $104.00
Crude Oil Swap NYMEX 10/13 - 12/13 92,000 $98.00
Crude Oil Swap NYMEX 10/13 - 12/13 46,000 $94.15
Crude Oil Swap NYMEX 10/13 - 12/13 46,000 $94.00
Crude Oil Swap NYMEX 10/13 - 12/13 92,000 $97.45
Crude Oil Swap NYMEX 10/13 - 12/13 92,000 $94.15
Crude Oil Swap NYMEX 10/13 - 12/13 92,000 $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 - 6/14 181,000 $98.00
Crude Oil Swap NYMEX 1/14 - 6/14 181,000 $99.00
Crude Oil Swap NYMEX 1/14 - 6/14 181,000 $100.07
Crude Oil Swap NYMEX 1/14 - 12/14 365,000 $94.05
Crude Oil Swap NYMEX 1/14 - 12/14 365,000 $95.00
Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $94.25
Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $95.00
Crude Oil Swap NYMEX 7/14 - 12/14 184,000 $95.25
Natural Gas Swap NYMEX 10/13 - 12/13 920,000 $3.76
Natural Gas Swap NYMEX 10/13 - 12/13 920,000 $3.90
Natural Gas Swap NYMEX 10/13 - 12/13 920,000 $4.00
Natural Gas Swap NYMEX 10/13 - 12/13 1,840,000 $3.50
Natural Gas Swap NYMEX 10/13 - 12/14 4,570,000 $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 Nine Months Ended
    September 30,   September 30,
    2013   2012   2013   2012
(Dollars in millions, where applicable)
Operating revenues  

$
68.3    

$
63.5    

$
189.9    

$
174.4  
Operating expenses:    
Fuel and purchased power 20.0 17.6 59.8 51.2
Operation and maintenance 19.5 17.9 56.4 53.1
Depreciation, depletion and amortization 8.1 8.1 24.6 24.2
Taxes, other than income     2.7       2.6       8.4       7.9  
      50.3       46.2       149.2       136.4  
Operating income     18.0       17.3       40.7       38.0  
Earnings  

$
11.4    

$
11.0    

$
25.7    

$
23.0  
Retail sales (million kWh) 795.2 753.8 2,329.4 2,189.8
Sales for resale (million kWh) 5.4 8.9 21.5 11.8
Average cost of fuel and purchased power per kWh  

$
.024    

$
.022    

$
.024    

$
.022  
 
Natural Gas Distribution
 
Three Months Ended Nine Months Ended
    September 30,   September 30,
    2013   2012   2013   2012
(Dollars in millions)
Operating revenues  

$
77.5    

$
80.1    

$
536.8    

$
504.8  
Operating expenses:
Purchased natural gas sold 36.5 38.0 323.5 300.2
Operation and maintenance 35.1 31.8 104.9 102.9
Depreciation, depletion and amortization 12.7 11.4 37.3 34.0
Taxes, other than income     7.3       7.0       32.9       33.2  
      91.6       88.2       498.6       470.3  
Operating income (loss)     (14.1 )     (8.1 )     38.2       34.5  
Earnings (loss)  

$
(11.2 )  

$
(8.8 )  

$
15.4    

$
10.3  
Volumes (MMdk):
Sales 7.6 8.0 67.7 60.1
Transportation     37.0       30.0       105.6       94.7  
Total throughput     44.6       38.0       173.3       154.8  
Degree days (% of normal)*
Montana-Dakota/Great Plains 34 % 38 % 101 % 75 %
Cascade 74 % 91 % 92 % 98 %
Intermountain     89 %     51 %     109 %     92 %
* Degree days are a measure of the daily temperature-related demand for energy for heating.
 

The combined utility businesses reported earnings of $200,000 in the third quarter of 2013, compared to earnings of $2.2 million for the same period in 2012. This decrease in earnings reflects higher operation and maintenance expense, largely payroll-related, as well as higher depreciation, depletion and amortization expense. Partially offsetting the decrease was higher electric retail sales margins, largely the result of 5 percent higher volumes.

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

  • The company filed an application Sept. 18 with the North Dakota Public Service Commission for a natural gas rate increase requesting a total of $6.8 million annually or approximately 6.4 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, an operations building, automated meter reading and a new customer billing system. The company requested an interim increase, subject to refund, of $4.5 million or approximately 4.2 percent. On Oct. 23, a settlement agreement was filed reflecting an increase of $4.3 million annually or approximately 4 percent including interim rates in the same amount to be effective with service rendered beginning Nov. 17. An informal hearing is scheduled for Nov. 13.
  • The company filed an application June 14 for an advance determination of prudence with NDPSC to add pollution control equipment at the Lewis & Clark generating station projected to be completed in 2016 to comply with the Mercury and Air Toxics Standards rules. On Oct. 9, the commission issued an order approving the ADP. Project cost is estimated to be $27.7 million.
  • The company filed an application Feb. 11 with NDPSC for approval of an environmental cost recovery rider related to ongoing construction costs at the Big Stone Station for the installation of the best-available retrofit technology air-quality control system. A hearing was held Sept. 16. The company's share of the cost for the installation is estimated at $100 million and is expected to be complete in 2015. The commission has approved advance determination of prudence for recovery of costs.
  • 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, an operations building, automated meter reading and new customer billing system. The company implemented the full request July 22, subject to refund. On Oct. 24, a settlement stipulation was filed reflecting a rate increase of $900,000 annually, or approximately 2 percent, which was approved by the commission at a hearing held today. The new rates will be effective Dec. 1.
  • The company filed an application Sept. 26, 2012, with the Montana Public Service Commission for a natural gas rate increase requesting a total of $3.5 million annually or approximately 5.9 percent above current rates. The case includes the costs associated with the increased investment in facilities, including ongoing investment in new and replacement distribution facilities, 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 was held Aug. 5 and 6.
  • The company is constructing an 88-megawatt simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $77 million and a projected in-service date in third quarter 2014. It is located on owned property adjacent to the company's Heskett Generating Station near Mandan, N.D. The capacity is necessary to meet the requirements of the company's integrated electric system customers and will be a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the NDPSC.
  • Investments are being made in 2013 totaling approximately $70 million to serve the growing electric and natural gas customer base associated with the Bakken oil development where customer growth is substantially higher than the national average.
  • Rate base growth is projected to be approximately 6 percent compounded annually over the next five years, including plans for an approximate $1 billion capital investment program.
  • 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 on a 30-mile, $62 million, natural gas line project into the Hanford Nuclear Site in Washington.
  • The company along with a partner expects to build a 345kv transmission line from Ellendale, N.D., to Big Stone City, S.D., about 160 miles, at a total cost of approximately $360 million. The company's share would be one-half. The project is a Midwest Independent Transmission System Operator multi-value project. A route application was filed in August with the state of South Dakota, and in October with the state of North Dakota. The project is expected to be complete in 2019.
  • The company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho.
Pipeline and Energy Services      
Three Months Ended Nine Months Ended
      September 30,   September 30,  
      2013   2012   2013     2012  
(Dollars in millions)
Operating revenues   $ 51.3   $ 48.3   $ 148.6       $ 141.6    
Operating expenses:  
Purchased natural gas sold 14.0 10.8 42.6 35.4
Operation and maintenance 16.1 19.2 65.3 * 34.8 **
Depreciation, depletion and amortization 7.1 7.3 22.0 20.4
  Taxes, other than income   3.3   3.5   10.3       10.5    
      40.5   40.8   140.2       101.1    
Operating income   10.8   7.5   8.4       40.5    
Earnings   $ 5.3   $ 3.3   $ 1.3   *   $ 21.9   **
Natural gas gathering asset impairment 9.0 1.7
  Net benefit related to natural gas gathering operations litigation             (15.0 )  
Adjusted earnings   $ 5.3   $ 3.3   $ 10.3       $ 8.6    
Transportation volumes (MMdk) 52.1 34.1 129.2 103.0
Natural gas gathering volumes (MMdk) 10.6 10.7 30.5 36.5
Customer natural gas storage balance (MMdk):
Beginning of period 25.2 40.4 43.7 36.0
  Net injection (withdrawal)   12.9   8.8   (5.6 )     13.2    
  End of period   38.1   49.2   38.1       49.2    

*

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 operation and maintenance expense, as well as an impairment of coalbed natural gas gathering assets of $2.7 million ($1.7 million after tax).

This segment reported third quarter earnings of $5.3 million, compared to $3.3 million in 2012. The company saw higher earnings from its interest in the Pronghorn natural gas and oil midstream assets, primarily from higher volumes. Also contributing were lower operation and maintenance expense, largely lower payroll-related, contract services and legal, as well as higher transportation volumes. Partially offsetting these increases was lower storage services revenue.

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 and, when complete, it will process Bakken crude into diesel, which will be marketed within the Bakken region. Total project costs are estimated to be approximately $300 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 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.
  • The company is engaged in various natural gas pipeline projects to be constructed in 2014. Namely 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 $53 million.
  • In May, the company announced plans for a proposed 400-mile natural gas pipeline from western North Dakota to western Minnesota to transport natural gas to markets in eastern North Dakota, Minnesota and Wisconsin. The company is evaluating alternate routes that would terminate further north, providing customers with access to additional markets via interconnections with Great Lakes Gas Transmission, TransCanada and Viking Gas Transmission in northwest Minnesota. The pipeline initially 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 $650 million to $700 million. Following an open season and receipt of adequate capacity commitments and necessary permits and regulatory approvals, construction on the new pipeline would begin as early as 2016.
  • On Oct. 31, WBI Energy Transmission filed a Section 4 rate case with the FERC, the first case it has filed in approximately 14 years. An increase in investments of $312 million and increased operating costs since 1999, combined with reduced storage and off system volumes because of narrowed basis and seasonal price spreads, which have resulted from shale gas developments in the United States, are the drivers for the requested rate increase of $28.9 million annually. The proposed effective date of the rates is Dec. 1.
  • The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region is expanding, most notably in the Bakken area, where the company owns an extensive natural gas pipeline system. Ongoing energy development is expected to continue to provide growth opportunities for this business.

Construction
   
Construction Materials and Contracting
Three Months Ended Nine Months Ended
    September 30,   September 30,
    2013   2012   2013   2012
(Dollars in millions)
Operating revenues   $ 714.4   $ 650.0   $ 1,312.0   $ 1,241.5
Operating expenses:    
Operation and maintenance 600.9 549.6 1,148.8 1,103.3
Depreciation, depletion and amortization 19.0 20.3 56.7 59.9
Taxes, other than income   11.6   11.0   30.7   29.6
    631.5   580.9   1,236.2   1,192.8
Operating income   82.9   69.1   75.8   48.7
Earnings   $ 49.2   $ 41.9   $ 38.6   $ 24.7
Sales (000's):
Aggregates (tons) 9,902 9,009 19,012 17,983
Asphalt (tons) 3,311 3,013 4,978 4,874
Ready-mixed concrete (cubic yards)   1,132   1,105   2,458   2,410
 
Construction Services
Three Months Ended Nine Months Ended
    September 30,   September 30,
    2013   2012   2013   2012
(In millions)
Operating revenues   $ 270.1   $ 247.2   $ 781.1   $ 689.4
Operating expenses:
Operation and maintenance 238.8 219.9 683.2 606.5
Depreciation, depletion and amortization 3.0 2.8 8.9 8.3
Taxes, other than income   7.3   7.2   25.3   22.1
    249.1   229.9   717.4   636.9
Operating income   21.0   17.3   63.7   52.5
Earnings   $ 12.2   $ 9.9   $ 36.7   $ 30.0
 

The combined construction businesses reported third quarter earnings of $61.4 million, compared to earnings of $51.8 million a year ago. The earnings increase reflects higher equipment sales and rental margins and higher workloads and margins in the Central and Western regions at the services group, and higher aggregate and asphalt margins and volumes at the materials group. On a combined basis, partially offsetting the earnings increase was higher selling, general and administrative expenses.

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

  • The construction materials approximate work backlog as of Sept. 30 was $525 million, compared to $464 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 $433 million, compared to $370 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 as of Sept. 30 was $157 million, including a $55 million North Dakota highway construction contract, the largest contract in the company's history. North Dakota backlog was $65 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 Nine Months Ended
    September 30,   September 30,
    2013   2012   2013   2012
(In millions)
Operating revenues   $ 2.3     $ 2.3     $ 6.8     $ 7.0
Operating expenses:    
Operation and maintenance (1.4 ) 1.5 1.2 4.4
Depreciation, depletion and amortization .5 .5 1.5 1.5
Taxes, other than income   .1         .2     .1
    (.8 )   2.0     2.9     6.0
Operating income   3.1     .3     3.9     1.0
Income from continuing operations 1.3 .8 2.1 1.9
Income (loss) from discontinued operations, net of tax   (.1 )   (.1 )   (.2 )   4.8
Earnings   $ 1.2     $ .7     $ 1.9     $ 6.7
 

This segment reported third quarter earnings of $1.2 million, compared to earnings of $700,000 a year ago. The earnings increase resulted from lower insurance costs, partially offset by lower earnings from equity method investments.

Use of Non-GAAP Financial MeasuresThe 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, 2013 and 2012:
  • A write-down of oil and natural gas properties of $100.9 million after tax in 2012.
  • An unrealized commodity derivatives loss of $7.9 million after tax in 2013, and $700,000 after tax in 2012.

Nine Months Ended September 30, 2013 and 2012:
  • A write-down of oil and natural gas properties of $100.9 million after tax in 2012.
  • A reversal of an arbitration charge of $15.0 million after tax in 2012.
  • Natural gas gathering asset impairments of $9.0 million after tax in 2013, and $1.7 million after tax in 2012.
  • An unrealized commodity derivatives loss of $3.4 million after tax in 2013, and $200,000 after tax in 2012.

Twelve Months Ended September 30, 2013 and 2012:
  • Write-downs of oil and natural gas properties of $145.9 million after tax in 2013, and $100.9 million after tax in 2012.
  • A reversal of an arbitration charge of $15.0 million after tax in 2012.
  • Natural gas gathering asset impairments of $9.0 million after tax in 2013, and $1.7 million after tax in 2012.
  • An unrealized commodity derivatives loss of $3.5 million after tax in 2013, and an unrealized commodity derivatives gain of $800,000 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 ResultsThe information in this release includes certain forward-looking statements, including earnings per share guidance and statements by the president and CEO of MDU Resources, within the meaning of Section 21E of the Securities Exchange Act of 1934. Although the company believes that its expectations are based on reasonable assumptions, actual results may differ materially. Following are important factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements.

  • The company’s exploration and production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, that are subject to various external influences that cannot be controlled.
  • The regulatory approval, permitting, construction, startup and/or operation of power generation facilities and Dakota Prairie Refinery may involve unanticipated events or delays that could negatively impact the company’s business and its results of operations and cash flows.
  • Economic volatility affects the company’s operations, as well as the demand for its products and services and the value of its investments and investment returns including its pension and other postretirement benefit plans, and may have a negative impact on the company’s future revenues and cash flows.
  • The company relies on financing sources and capital markets. Access to these markets may be adversely affected by factors beyond the company’s control. If the company is unable to obtain economic financing in the future, the company’s ability to execute its business plans, make capital expenditures or pursue acquisitions that the company may otherwise rely on for future growth could be impaired. As a result, the market value of the company’s common stock may be adversely affected. If the company issues a substantial amount of common stock it could have a dilutive effect on its existing shareholders.
  • The company is exposed to credit risk and the risk of loss resulting from the nonpayment and/or nonperformance by the company’s customers and counterparties.
  • The backlogs at the company’s construction materials and contracting and construction services businesses are subject to delay or cancellation and may not be realized.
  • Actual quantities of recoverable oil, natural gas liquids and natural gas reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. There is a risk that changes in estimates of proved reserve quantities or other factors including downward movements in prices, could result in additional future noncash write-downs of the company's oil and natural gas properties.
  • The company’s operations are subject to environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the company to environmental liabilities.
  • Initiatives to reduce greenhouse gas emissions could adversely impact the company’s operations.
  • The company is subject to government regulations that may delay and/or have a negative impact on its business and its results of operations and cash flows. Statutory and regulatory requirements also may limit another party’s ability to acquire the company.
  • Weather conditions can adversely affect the company’s operations, revenues and cash flows.
  • Competition is increasing in all of the company’s businesses.
  • The company could be subject to limitations on its ability to pay dividends.
  • An increase in costs related to obligations under multiemployer pension plans could have a material negative effect on the company’s results of operations and cash flows.
  • The company's operations may be negatively impacted by cyber attacks or acts of terrorism.
  • Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include:
    • Acquisition, disposal and impairments of assets or facilities.
    • Changes in operation, performance and construction of plant facilities or other assets.
    • Changes in present or prospective generation.
    • The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings.
    • The availability of economic expansion or development opportunities.
    • Population growth rates and demographic patterns.
    • Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services.
    • The cyclical nature of large construction projects at certain operations.
    • Changes in tax rates or policies.
    • Unanticipated project delays or changes in project costs, including related energy costs.
    • Unanticipated changes in operating expenses or capital expenditures.
    • Labor negotiations or disputes.
    • Inability of the various contract counterparties to meet their contractual obligations.
    • Changes in accounting principles and/or the application of such principles to the company.
    • Changes in technology.
    • Changes in legal or regulatory proceedings.
    • The ability to effectively integrate the operations and the internal controls of acquired companies.
    • The ability to attract and retain skilled labor and key personnel.
    • Increases in employee and retiree benefit costs and funding requirements.

For a further discussion of these risk factors and cautionary statements, refer to Item 1A – Risk Factors in the company’s most recent Form 10-K and Form 10-Q.
MDU Resources Group, Inc.    
Three Months Ended Nine Months Ended
    September 30,   September 30,
    2013   2012   2013   2012
(In millions, except per share amounts)
(Unaudited)
Operating revenues   $ 1,285.8     $ 1,173.5     $ 3,278.0     $ 2,994.3
Operating expenses:    
Fuel and purchased power 20.0 17.6 59.8 51.2
Purchased natural gas sold 35.8 35.2 305.3 279.1
Operation and maintenance 934.3 861.7 2,132.5 1,982.3
Depreciation, depletion and amortization 100.0 91.8 288.8 260.9
Taxes, other than income 45.8 41.1 145.8 132.0
Write-down of oil and natural gas properties       160.1         160.1
    1,135.9     1,207.5     2,932.2     2,865.6
Operating income (loss) 149.9 (34.0 ) 345.8 128.7
Earnings (loss) from equity method investments (.1 ) 2.4 (.4 ) 4.0
Other income 2.3 1.7 5.0 4.1
Interest expense   21.0     19.9     63.3     56.9
Income (loss) before income taxes 131.1 (49.8 ) 287.1 79.9
Income taxes   46.5     (20.3 )   99.6     24.5
Income (loss) from continuing operations 84.6 (29.5 ) 187.5 55.4
Income (loss) from discontinued operations, net of tax   (.1 )   (.1 )   (.2 )   4.8
Net income (loss) 84.5 (29.6 ) 187.3 60.2
Net loss attributable to noncontrolling interest (.2 )
Dividends declared on preferred stocks   .2     .2     .5     .5
Earnings (loss) on common stock   $ 84.3     $ (29.8 )   $ 187.0     $ 59.7
 
Earnings (loss) per common share – basic:
Earnings (loss) before discontinued operations $ .45 $ (.16 ) $ .99 $ .29
Discontinued operations, net of tax               .03
Earnings (loss) per common share – basic   $ .45     $ (.16 )   $ .99     $ .32
Earnings (loss) per common share – diluted:
Earnings (loss) before discontinued operations $ .44 $ (.16 ) $ .99 $ .29
Discontinued operations, net of tax               .03
Earnings (loss) per common share – diluted   $ .44     $ (.16 )   $ .99     $ .32
Dividends declared per common share   $ .1725     $ .1675     $ .5175     $ .5025
Weighted average common shares outstanding – basic   188.8     188.8     188.8     188.8
Weighted average common shares outstanding – diluted   189.6     188.8     189.6     189.0
 

 
    Nine Months Ended
September 30,
2013     2012
(Unaudited)
 
Other Financial Data
Book value per common share $ 14.49 $ 14.45
Market price per common share $ 27.97 $ 22.04
Dividend yield (indicated annual rate) 2.5 % 3.0 %
Price/adjusted earnings ratio*

19.3

x

19.3

x
Market value as a percent of book value 193.0 % 152.5 %
Net operating cash flow** $ 429 $ 329
Total assets** $ 7,167 $ 6,903

Total equity**
$ 2,750 $ 2,743
Total debt ** $ 2,019 $ 1,754
Capitalization ratios:
Total equity 58 % 61 %
Total debt 42   39  
100 % 100 %

*

Represents 12 months ended. On a GAAP earnings basis, the ratio is not meaningful.

**

In millions

Copyright Business Wire 2010

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