MDU Resources Reports Improved First Quarter Earnings, Reaffirms 2011 Earnings Guidance
| | · | Consolidated earnings of $42.8 million, or 23 cents per share. |
| | · | Strong balance sheet with equity of 65% of total capital. |
| | · | Second oil rig now on site in Bakken. |
| | · | Reaffirming earnings guidance for 2011 of $1.05 to $1.30 per common share. |
BISMARCK, N.D. – May 2, 2011 – MDU Resources Group, Inc. (NYSE:MDU) today reported first quarter consolidated earnings of $42.8 million, or 23 cents per common share, compared to $41.6 million, or 22 cents per common share for the first quarter of 2010.
“We are off to a good start with earnings that are stronger than a year ago,” said Terry D. Hildestad, president and chief executive officer of MDU Resources. “We increased our oil production even with weather challenges, and our utility and construction services businesses reported higher earnings. These improvements along with successful resolution of several open tax years which reduced our tax expense, more than offset lower natural gas prices and the absence of earnings from Brazilian transmission assets sold last year.
“Overall, this was a successful quarter and earnings results exceeded our projection,” he said. “We continue to focus on growth and plan to invest $565 million this year, with more than $300 million allocated to our E&P business where we are heavily focused on increasing oil production.
“Our financial strategy of the past several years is paying off. We have a strong balance sheet and good liquidity that can support this exploration and production growth, and at the same time positions all of our businesses to take advantage of the growth opportunities that we expect to occur in a recovering economy.”
The exploration and production business continues to focus on balancing its production mix. Oil production increased 5 percent over the same period last year, and now accounts for nearly 30 percent of total production. Although the segment’s Bakken oil production grew by 21 percent from a year ago, development and production were constrained by severe winter weather that affected most companies working in the region.
This segment is ramping up its investment to nearly $90 million to develop Bakken reserves this year. A second drilling rig recently arrived in the Bakken and will soon begin drilling in Mountrail County. The company plans to drill 18 wells in the oil play this year.
The pipeline and energy services business experienced lower gathering and transportation volumes. This decline includes lower volumes transported to storage, which combined with higher withdrawals from storage, resulted in a 24 percent decline in total customer storage balances at the end of the first quarter.
Significantly colder weather throughout its service territory resulted in a 15 percent increase in natural gas sales, and helped lead the utility business segment to strong first quarter earnings. Electric retail sales increased 6 percent as a result of the colder temperatures. The recovery of the investment made in Wyoming generation also benefited the utility as new rates went into effect in Wyoming during the second quarter last year.
Poor weather affected the start of the construction season adding to the normal seasonal loss for the construction materials and contracting segment. Although the business continues to be affected by the weak housing market and lack of long-term federal highway funding, it is experiencing steady bidding opportunities. The work backlog at the end of the quarter increased to $569 million, including a harbor expansion project in California that is expected to get underway in the second quarter.
The construction services segment experienced a quarter-to-quarter improvement, driven by increased workloads in the western region and continued strong equipment sales and rental. Revenues were $50 million higher, a 33 percent increase over last year. Backlog at the end of the quarter stood at $347 million.
“We are pursuing a variety of growth opportunities and are excited about the outlook,” Hildestad said. “Excluding acquisitions, our plans include investing $3.5 billion over the next five years primarily for organic growth, a 27 percent increase over capital invested during the prior five-year period. We expect to fund these capital expenditures without having to issue external equity. And, we are pursuing growth through acquisitions which would be incremental to this investment. We believe our long term prospects are strong.”
The company will host a webcast at 11 a.m. EDT on Tuesday, May 3 to discuss earnings results and guidance. The event can be accessed at www.mdu.com. A webcast replay and audio replay will be available. The dial-in number for audio replay is (800) 642-1687 or for international callers, (706) 645-9291, conference ID 55658893.
MDU Resources Group, Inc., a Fortune 500 company and 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 businesses, an exploration and production company and construction companies. MDU Resources includes regulated electric and natural gas utilities and regulated natural gas pipelines and energy services, natural gas and oil production, construction materials and contracting, and construction services. For more information about MDU Resources, see the company's Web site at www.mdu.com or contact the Investor Relations Department at investor@mduresources.com.
Contacts
Financial:
Phyllis A. Rittenbach, director - investor relations, (701) 530-1057
Media:
Rick Matteson, director of communications and public affairs, (701) 530-1700
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.
| Business Line | | Earnings First Quarter 2011 (In Millions) | | | Earnings First Quarter 2010 (In Millions) | |
| Exploration and Production | | | | | | |
Natural gas and oil production | | $ | 16.3 | | | $ | 22.2 | |
| Regulated | | | | | | | | |
Pipeline and energy services | | | 6.9 | | | | 8.8 | |
Electric and natural gas utilities | | | 36.0 | | | | 29.2 | |
| Construction | | | | | | | | |
Construction materials and contracting | | | (21.4 | ) | | | (20.1 | ) |
Construction services | | | 4.6 | | | | .1 | |
| Other | | | (.1 | ) | | | 1.4 | |
| Earnings before discontinued operations | | | 42.3 | | | | 41.6 | |
| Income from discontinued operations, net of tax | | | .5 | | | | --- | |
| Earnings on common stock | | $ | 42.8 | | | $ | 41.6 | |
On a consolidated basis, the following information highlights the key growth strategies, projections and certain assumptions for the company:
| | · | Earnings per common share for 2011, diluted, are projected in the range of $1.05 to $1.30. The company expects the approximate percentage of 2011 earnings per common share by quarter to be: |
| | – | Second quarter – 20 percent |
| | – | Third quarter – 35 percent |
| | – | Fourth quarter – 25 percent |
| | · | Although near term market conditions are uncertain, the company’s long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent. |
| | · | The company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities. |
| | · | Estimated capital expenditures for 2011 are approximately $565 million. The company expects the 2011 estimated capital expenditures to be funded in its entirety with cash flow generated from operations. |
Exploration and Production
Natural Gas and Oil Production
| | | Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| (Dollars in millions, where applicable) | |
| Operating revenues: | | | | | | |
| Natural gas | | $ | 45.4 | | | $ | 57.5 | |
| Oil | | | 58.6 | | | | 50.1 | |
| | | | 104.0 | | | | 107.6 | |
| Operating expenses: | | | | | | | | |
| Operation and maintenance: | | | | | | | | |
| Lease operating costs | | | 18.0 | | | | 15.8 | |
| Gathering and transportation | | | 5.7 | | | | 5.8 | |
| Other | | | 8.3 | | | | 8.7 | |
| Depreciation, depletion and amortization | | | 34.2 | | | | 29.7 | |
| Taxes, other than income: | | | | | | | | |
| Production and property taxes | | | 10.1 | | | | 9.5 | |
| Other | | | .3 | | | | .3 | |
| | | | 76.6 | | | | 69.8 | |
| Operating income | | | 27.4 | | | | 37.8 | |
| Earnings | | $ | 16.3 | | | $ | 22.2 | |
| Production: | | | | | | | | |
| Natural gas (MMcf) | | | 11,758 | | | | 12,243 | |
| Oil (MBbls) | | | 802 | | | | 761 | |
| Total Production (MMcfe) | | | 16,570 | | | | 16,808 | |
| Average realized prices (including hedges): | | | | | | | | |
| Natural gas (per Mcf) | | $ | 3.86 | | | $ | 4.70 | |
| Oil (per barrel) | | $ | 72.98 | | | $ | 65.79 | |
| Average realized prices (excluding hedges): | | | | | | | | |
| Natural gas (per Mcf) | | $ | 3.39 | | | $ | 4.56 | |
| Oil (per barrel) | | $ | 79.24 | | | $ | 66.40 | |
| Average depreciation, depletion and amortization rate, per equivalent Mcf | | $ | 1.96 | | | $ | 1.67 | |
| Production costs, including taxes, per equivalent Mcf: | | | | | | | | |
| Lease operating costs | | $ | 1.09 | | | $ | .94 | |
| Gathering and transportation | | | .34 | | | | .35 | |
| Production and property taxes | | | .61 | | | | .56 | |
| | | $ | 2.04 | | | $ | 1.85 | |
Earnings at this segment were $16.3 million in the first quarter of 2011 compared to $22.2 million in 2010. This decrease reflects lower average realized natural gas prices of 18 percent, higher depreciation, depletion and amortization expense, increased lease operating costs, as well as decreased natural gas production. These decreases were partially offset by higher average realized oil prices of 11 percent and increased oil production of 5 percent.
In March the company announced the addition of industry veteran J. Kent Wells effective May 2. Kent is the president and chief executive officer of the corporation’s natural gas and oil production business. His extensive experience spans more than 30 years with BP and Amoco, including responsibility for BP’s U.S. onshore natural gas business.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
| | · | Capital expenditures in 2011 are expected to be $306 million. The company continues its focus on returns by allocating a growing portion of its capital investment into the production of oil in the current commodity price environment. Its capital program reflects further exploitation of existing properties, acquisition of additional leasehold acreage, and exploratory drilling. The 2011 planned capital expenditure total does not include potential acquisitions of producing properties. |
| | · | For 2011, the company expects a 5 percent to 10 percent increase in oil production offset by a 4 percent to 8 percent decrease in natural gas production. If natural gas prices recover, the company believes it is positioned to spend additional capital on drilling its low cost natural gas properties. |
| | · | The company added a second drilling rig in the Bakken in late April. |
| | · | Bakken – Mountrail County, North Dakota |
| | o | The company owns approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations. The drilling of 12 operated and participation in various non-operated wells is planned for 2011 with approximately $52 million of capital expenditures. Plans include drilling 12 wells annually for the two-year period 2012 through 2013. |
| | o | Over 50 future wells sites have been identified, 20 middle Bakken infill locations and the remainder Three Forks locations. Estimated gross ultimate recovery per well for the middle Bakken wells is 250,000 to 400,000 barrels. |
| | · | Bakken – Stark County, North Dakota |
| | o | The company holds approximately 50,000 net exploratory leasehold acres, targeting the Three Forks formation. It anticipates drilling 6 operated wells on this acreage and participating in various non-operated wells in Stark County in 2011 with capital of approximately $37 million. |
| | o | Based on well results, the company plans to drill 12 or more wells annually beginning in 2012. |
| | o | Based on 640-acre spacing, the acreage holds over 75 potential drill sites. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 barrels of oil equivalents. Based on initial well results and results by certain other producers, the play appears promising. |
| | · | Niobrara – southeastern Wyoming |
| | o | The company holds approximately 65,000 net exploratory leasehold acres in this emerging oil play. It is completing seismic evaluation work on this acreage and expects to begin drilling 2 exploratory wells in 2011. |
| | o | If successful, the company plans to initiate a drilling program of approximately 12 wells annually starting in 2012. |
| | o | The company also expects to participate in various non-operated wells in the Niobrara. |
| | o | The company has more than 100 future locations on this acreage based on 640-acre spacing. Although this is an emerging exploratory play, early results by certain other producers appear promising. |
| | o | Based on low natural gas prices, the company is targeting areas that have the potential for higher liquids content. It has approximately $48 million of capital targeted in 2011. |
| | o | The company holds approximately 80,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana. Plans include drilling a test well in 2011. |
| | o | The company continues to pursue acquisitions of additional leaseholds. Approximately $50 million of capital has been allocated to leasehold acquisitions in 2011, focusing on expansion of existing positions and new opportunities. |
| | · | Earnings guidance reflects estimated natural gas and oil prices for May through December as follows: |
| Natural Gas Index: | |
| NYMEX | $4.00 to $4.50 per Mcf |
| Ventura | $3.75 to $4.25 per Mcf |
| CIG | $3.50 to $4.00 per Mcf |
| | |
| Crude Oil Index: | |
| NYMEX | $95.00 to $100.00 per barrel |
| | · | For the last nine months of 2011, the company has hedged approximately 50 percent to 55 percent of its estimated natural gas production and 60 percent to 65 percent of its estimated oil production. For 2012, it has hedged 20 percent to 25 percent of its estimated natural gas production and 45 percent to 50 percent of its estimated oil production. The hedges that are in place as of May 2 are summarized in the following chart: |
| Commodity | Type | Index | Period Outstanding | Forward Notional Volume (MMBtu/Bbl) | Price (Per MMBtu/Bbl) |
| Natural Gas | Swap | HSC | 4/11 - 12/11 | 1,017,500 | $8.00 |
| Natural Gas | Swap | NYMEX | 4/11 - 12/11 | 3,025,000 | $6.1027 |
| Natural Gas | Swap | NYMEX | 4/11 - 12/11 | 2,750,000 | $5.4975 |
| Natural Gas | Swap | NYMEX | 4/11 - 12/11 | 2,750,000 | $4.58 |
| Natural Gas | Swap | NYMEX | 4/11 - 12/11 | 2,750,000 | $4.70 |
| Natural Gas | Swap | NYMEX | 4/11 - 12/11 | 2,750,000 | $4.75 |
| Natural Gas | Swap | NYMEX | 4/11 - 10/11 | 2,140,000 | $4.775 |
| Natural Gas | Swap | Ventura | 5/11 - 10/11 | 1,840,000 | $4.365 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 3,477,000 | $6.27 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 1,830,000 | $5.005 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 915,000 | $5.005 |
| Natural Gas | Swap | NYMEX | 1/12 - 12/12 | 915,000 | $5.0125 |
| Natural Gas | Swap | Ventura | 1/12 - 12/12 | 3,660,000 | $4.87 |
| Crude Oil | Collar | NYMEX | 4/11 - 12/11 | 412,500 | $80.00-$94.00 |
| Crude Oil | Collar | NYMEX | 4/11 - 12/11 | 275,000 | $80.00-$89.00 |
| Crude Oil | Collar | NYMEX | 4/11 - 12/11 | 137,500 | $77.00-$86.45 |
| Crude Oil | Collar | NYMEX | 4/11 - 12/11 | 137,500 | $75.00-$88.00 |
| Crude Oil | Swap | NYMEX | 4/11 - 12/11 | 275,000 | $81.35 |
| Crude Oil | Swap | NYMEX | 4/11 - 12/11 | 137,500 | $85.85 |
| Crude Oil | Put Option | NYMEX | 4/11 - 12/11 | 275,000 | $80.00* |
| Crude Oil | Call Option | NYMEX | 4/11 - 12/11 | 275,000 | $103.00* |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$87.80 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$94.50 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 366,000 | $80.00-$98.36 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 183,000 | $85.00-$102.75 |
| Crude Oil | Collar | NYMEX | 1/12 - 12/12 | 183,000 | $85.00-$103.00 |
| Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 183,000 | $100.10 |
| Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 183,000 | $100.00 |
| Crude Oil | Swap | NYMEX | 1/12 - 12/12 | 366,000 | $110.30 |
| Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 182,500 | $95.00-$117.00 |
| Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 182,500 | $95.00-$117.00 |
| Natural Gas | Basis Swap | CIG | 4/11 - 12/11 | 3,025,000 | $0.395 |
| Natural Gas | Basis Swap | Ventura | 4/11 - 12/11 | 2,750,000 | $0.15 |
| Natural Gas | Basis Swap | Ventura | 4/11 - 12/11 | 1,375,000 | $0.15 |
| Natural Gas | Basis Swap | Ventura | 4/11 - 12/11 | 687,500 | $0.16 |
| Natural Gas | Basis Swap | Ventura | 4/11 - 12/11 | 2,750,000 | $0.16 |
| Natural Gas | Basis Swap | Ventura | 4/11 - 12/11 | 3,437,500 | $0.155 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 2,745,000 | $0.405 |
| Natural Gas | Basis Swap | CIG | 1/12 - 12/12 | 732,000 | $0.41 |
* Deferred premium of $4.00. Put option was purchased. Call option was sold. Notes: · Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines. · For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column. |
Regulated
Pipeline and Energy Services
| | | Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 74.0 | | | $ | 88.6 | |
| Operating expenses: | | | | | | | | |
| Purchased natural gas sold | | | 34.1 | | | | 47.5 | |
| Operation and maintenance | | | 17.6 | | | | 15.2 | |
| Depreciation, depletion and amortization | | | 6.4 | | | | 6.4 | |
| Taxes, other than income | | | 3.6 | | | | 3.0 | |
| | | | 61.7 | | | | 72.1 | |
| Operating income | | | 12.3 | | | | 16.5 | |
| Earnings | | $ | 6.9 | | | $ | 8.8 | |
| Transportation volumes (MMdk) | | | 27.3 | | | | 30.5 | |
| Gathering volumes (MMdk) | | | 17.5 | | | | 19.1 | |
| Customer natural gas storage balance (MMdk): | | | | | | | | |
| Beginning of period | | | 58.8 | | | | 61.5 | |
| Net injection (withdrawal) | | | (25.9 | ) | | | (18.0 | ) |
| End of period | | | 32.9 | | | | 43.5 | |
This segment reported first quarter earnings of $6.9 million, compared to $8.8 million for the same period in 2010. This decrease reflects lower gathering and transportation volumes, as well as lower margin from energy-related services.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
| | · | The company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken of North Dakota and eastern Montana. It 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. |
| | · | The company solicited customer interest in a 27 MMcf per day expansion of its existing natural gas pipeline in the Bakken production area in northwestern North Dakota in the first quarter of 2011. Sufficient customer interest was received to move forward on a project. It continues to solicit further interest in the expansion. |
| | · | Final agreements have been executed to construct approximately 12 miles of high pressure transmission pipeline providing takeaway capacity for processed natural gas in northwestern North Dakota. The project is expected to be completed in the fourth quarter. The company believes it is in a good position to provide similar services for other natural gas processing facilities in the area. |
| | · | The company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. It continues to see interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by 125 MMcf per day. The company has received commitment on approximately 30 percent of the total potential project and is moving forward on this phase with a projected in-service date of November 2011. |
Electric and Natural Gas Utilities
| Electric | | | | | | |
| | | Three Months Ended March 31, |
| | | 2011 | | | 2010 | |
| (Dollars in millions, where applicable) |
| Operating revenues | | $ | 57.8 | | | $ | 49.7 | |
| Operating expenses: | | | | | | | | |
| Fuel and purchased power | | | 16.9 | | | | 16.9 | |
| Operation and maintenance | | | 16.0 | | | | 15.2 | |
| Depreciation, depletion and amortization | | | 8.2 | | | | 5.7 | |
| Taxes, other than income | | | 2.5 | | | | 2.7 | |
| | | | 43.6 | | | | 40.5 | |
| Operating income | | | 14.2 | | | | 9.2 | |
| Earnings | | $ | 8.5 | | | $ | 5.9 | |
| Retail sales (million kWh) | | | 794.7 | | | | 749.8 | |
| Sales for resale (million kWh) | | | 6.7 | | | | 29.8 | |
| Average cost of fuel and purchased power per kWh | | $ | .020 | | | $ | .021 | |
| | | | | | | | | |
| Natural Gas Distribution | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | 2011 | | | | 2010 | |
| (Dollars in millions) |
| Operating revenues | | $ | 370.4 | | | $ | 349.0 | |
| Operating expenses: | | | | | | | | |
| Purchased natural gas sold | | | 257.5 | | | | 245.2 | |
| Operation and maintenance | | | 34.4 | | | | 32.7 | |
| Depreciation, depletion and amortization | | | 11.1 | | | | 10.6 | |
| Taxes, other than income | | | 17.7 | | | | 16.5 | |
| | | | 320.7 | | | | 305.0 | |
| Operating income | | | 49.7 | | | | 44.0 | |
| Earnings | | $ | 27.5 | | | $ | 23.3 | |
| Volumes (MMdk): | | | | | | | | |
| Sales | | | 43.9 | | | | 38.1 | |
| Transportation | | | 34.1 | | | | 34.5 | |
| Total throughput | | | 78.0 | | | | 72.6 | |
| Degree days (% of normal)* | | | | | | | | |
| Montana-Dakota | | | 111 | % | | | 99 | % |
| Cascade | | | 103 | % | | | 86 | % |
| Intermountain | | | 105 | % | | | 95 | % |
| * Degree days are a measure of the daily temperature-related demand for energy for heating. |
The combined utility businesses reported earnings of $36.0 million in the first quarter of 2011, compared to earnings of $29.2 million for the same period in 2010. This increase reflects increased retail natural gas sales volumes, resulting from colder weather than last year, higher electric retail sales margins and volumes, as well as lower income taxes, including favorable resolution of certain income tax matters. Partially offsetting these increases were higher operation and maintenance expense and increased depreciation, depletion and amortization expense.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
| | · | In April 2010, the company filed an application with the North Dakota Public Service Commission for an electric rate increase of $15.4 million annually, or approximately 14 percent above current rates. The requested increase included the investment in infrastructure upgrades, recovery of the investment in renewable generation, the costs associated with the Big Stone II plant and the significant loss of wholesale sales margins. In June, the NDPSC approved an interim increase of $7.6 million effective with service rendered June 18, 2010. In June, the company and the NDPSC Advocacy Staff filed a partial settlement agreement agreeing to an overall rate of return and a sharing of earnings over a specified return on equity. In July, the company filed an amendment to its application to exclude the development costs associated with the Big Stone II plant because of a settlement agreement approved by the NDPSC that provided for recovery of such development costs. In November, the company and the NDPSC Advocacy Staff filed a second settlement agreement resolving certain issues. The company revised its requested rate increase to $8.8 million annually or 7.7 percent as a result of the settlements, the exclusion of the Big Stone II plant development costs and other adjustments. The NDPSC Advocacy Staff sought reductions of $8.3 million annually from the company’s requested increase. A hearing on the application was held in November. On March 14, the company, the NDPSC Advocacy Staff and the Missouri Valley Resource Council filed a settlement agreement that resolved all outstanding issues in the case, resulting in an increase of $7.6 million. The NDPSC has set a hearing on the settlement for May 5. |
| | · | In August, the company filed an application with the Montana Public Service Commission for an electric rate increase of $5.5 million annually, or approximately 13 percent above current rates. The requested increase included the investment in infrastructure upgrades, recovery of the investment in renewable generation, the costs associated with the Big Stone II plant and the significant loss of wholesale sales margins. Montana-Dakota requested an interim increase of $3.1 million or approximately 7.4 percent. On Feb. 8, the MTPSC approved an interim increase of $2.6 million or approximately 6.3 percent, effective with service rendered Feb. 14. On Feb. 23, Montana-Dakota and interveners to the case jointly requested that the hearing set for Feb. 28 be vacated and reset to a later date as the parties believed they would be able to negotiate a settlement agreement. The hearing was vacated on Feb. 23. Settlement discussions are ongoing. |
| | · | The company is analyzing potential projects for accommodating load growth and replacing purchased power contracts with company-owned generation. The company is reviewing the construction of natural gas-fired combustion generation. |
| | · | The company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major market areas. The company has signed a contract to develop a 30-mile high-voltage power line in southeast North Dakota to move power to the electric grid from a proposed 150-MW wind farm. The proposed project will total approximately $20 million and will include substation upgrades with construction expected to begin in 2011. Its customers would not bear any of the costs associated with the project as costs will be recovered through an approved interconnect tariff. A major market party to the wind farm project has recently announced its intentions to withdraw from the project which may affect development of the associated power line by the company. |
| | · | The South Dakota Board of Minerals and Environment has approved rules implementing the South Dakota Regional Haze Program that upon approval by the EPA will require the Big Stone Station to install and operate a best available retrofit technology (BART) air quality control system to reduce emissions of particulate matter, sulfur dioxide and nitrogen oxides as early as January 2016. The company’s share of the cost of this air quality control system could exceed $100 million. At this time the company believes continuing to operate Big Stone Station with the upgrade is the best option; however, it will continue to review alternatives. The company intends to seek recovery of costs related to the above matter in electric rates charged to customers. |
Construction
Construction Materials and Contracting
| | | Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| | | (Dollars in millions) | |
| Operating revenues | | $ | 143.5 | | | $ | 149.8 | |
| Operating expenses: | | | | | | | | |
| Operation and maintenance | | | 146.8 | | | | 146.0 | |
| Depreciation, depletion and amortization | | | 21.5 | | | | 22.6 | |
| Taxes, other than income | | | 7.7 | | | | 7.2 | |
| | | | 176.0 | | | | 175.8 | |
| Operating loss | | | (32.5 | ) | | | (26.0 | ) |
| Loss | | $ | (21.4 | ) | | $ | (20.1 | ) |
| Sales (000's): | | | | | | | | |
| Aggregates (tons) | | | 2,827 | | | | 2,963 | |
| Asphalt (tons) | | | 165 | | | | 154 | |
| Ready-mixed concrete (cubic yards) | | | 397 | | | | 476 | |
The construction materials and contracting segment experienced a seasonal first-quarter loss of $21.4 million compared to a loss of $20.1 million a year ago. The increased loss was largely because of decreased construction margins and lower ready-mixed concrete and aggregate volumes and margins, which includes the effects of the continued economic downturn and weather-related delays. Partially offsetting the increased loss was an income tax benefit related to favorable resolution of certain income tax matters, as well as lower selling, general and administrative costs.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
| | · | Work backlog as of March 31 was approximately $569 million, with 93 percent of construction backlog being public work and private representing 7 percent. In the company’s peak earnings year of 2006, private backlog represented 40 percent of construction backlog. Backlog a year ago was comparable at $568 million. Total backlog at Dec. 31 was $420 million. |
| | · | Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and harbor expansion projects. |
| | · | The company is part of a joint venture that was recently selected as the low bidder on the Port of Long Beach expansion. Its share of the project for this phase is expected to exceed $25 million. The company is also the primary cement provider and has the opportunity to supply a portion of the ready-mixed concrete and aggregate related to a light rail project in Hawaii. In addition, it has several significant multi-year projects it will place bids on in 2011. The company also expects to place a new asphalt oil terminal into service in late 2011 in Wyoming. |
| | · | As a result of the continued slow recovery in the residential and commercial markets and uncertainty in federal and state transportation funding, the company expects overall 2011 volumes and margins to be comparable to 2010. |
| | · | Federal transportation stimulus of $7.9 billion was directed to states where the company operates. Of that amount, 69 percent was spent as of March 31, 2011, with the majority of the remaining $2.4 billion to be spent during the remainder of 2011. |
| | · | The company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets. |
| | · | The company has a strong emphasis on operational efficiencies and cost reduction. SG&A expenses are down approximately 40 percent for the trailing twelve months through March 31, compared to the annual expenses in 2006, the peak earnings year for this segment. |
| | · | As the country’s 6th 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. |
Construction Services
| | | Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| | | (In millions) | |
| Operating revenues | | $ | 203.4 | | | $ | 153.1 | |
| Operating expenses: | | | | | | | | |
| Operation and maintenance | | | 184.9 | | | | 141.8 | |
| Depreciation, depletion and amortization | | | 2.9 | | | | 3.3 | |
| Taxes, other than income | | | 7.7 | | | | 6.5 | |
| | | | 195.5 | | | | 151.6 | |
| Operating income | | | 7.9 | | | | 1.5 | |
| Earnings | | $ | 4.6 | | | $ | .1 | |
This segment had first quarter earnings of $4.6 million, compared to $100,000 a year ago. This earnings increase reflects higher construction workloads and margins, largely in the Western region. Also contributing to the earnings increase were higher equipment and electrical supply sales.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
| | · | Work backlog as of March 31 was approximately $347 million, compared to $400 million a year ago, and $373 million at Dec. 31. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work. |
| | · | As a result of the continued slow economic recovery, the company anticipates margins in 2011 to be comparable to 2010 levels. |
| | · | The company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction, governmental facilities, refinery turnaround projects and utility service work. |
| | · | The company continues to focus on costs and efficiencies to enhance margins. SG&A expenses are down approximately 30 percent for the trailing twelve months through March 31, compared to the annual expenses in 2008, the peak earnings year for this segment. |
| | · | With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure. |
Other
| | | Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| | | (In millions) | |
| Operating revenues | | $ | 2.5 | | | $ | 2.3 | |
| Operating expenses: | | | | | | | | |
| Operation and maintenance | | | 2.9 | | | | 1.9 | |
| Depreciation, depletion and amortization | | | .4 | | | | .4 | |
| Taxes, other than income | | | .1 | | | | .1 | |
| | | | 3.4 | | | | 2.4 | |
| Operating loss | | | (.9 | ) | | | (.1 | ) |
| Income (loss) from continuing operations | | | (.1 | ) | | | 1.4 | |
| Income from discontinued operations, net of tax | | | .5 | | | | --- | |
| Earnings | | $ | .4 | | | $ | 1.4 | |
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 chief executive officer 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 natural gas and oil production and pipeline and energy services businesses are dependent on factors, including commodity prices and commodity price basis differentials, which are subject to various external influences that cannot be controlled. |
| | · | The regulatory approval, permitting, construction, startup and operation of power generation facilities may involve unanticipated changes 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 services and construction materials and contracting businesses are subject to delay or cancellation and may not be realized. |
| | · | Actual quantities of recoverable natural gas and oil reserves and discounted future net cash flows from those reserves may vary significantly from estimated amounts. |
| | · | 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. |
| | · | Global climate change initiatives to reduce greenhouse gas emissions could adversely impact the company’s electric generation operations. |
| | · | The company's coalbed natural gas operations could be adversely impacted by the outcome of lawsuits challenging its coalbed natural gas development. |
| | · | 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. |
| | · | Other factors that could cause actual results or outcomes for the company to differ materially from those discussed in forward-looking statements include: |
| | o | Acquisition, disposal and impairments of assets or facilities. |
| | o | Changes in operation, performance and construction of plant facilities or other assets. |
| | o | Changes in present or prospective generation. |
| | o | The ability to obtain adequate and timely cost recovery for the company’s regulated operations through regulatory proceedings. |
| | o | The availability of economic expansion or development opportunities. |
| | o | Population growth rates and demographic patterns. |
| | o | Market demand for, available supplies of, and/or costs of, energy- and construction-related products and services. |
| | o | The cyclical nature of large construction projects at certain operations. |
| | o | Changes in tax rates or policies. |
| | o | Unanticipated project delays or changes in project costs, including related energy costs. |
| | o | Unanticipated changes in operating expenses or capital expenditures. |
| | o | Labor negotiations or disputes. |
| | o | Inability of the various contract counterparties to meet their contractual obligations. |
| | o | Changes in accounting principles and/or the application of such principles to the company. |
| | o | Changes in legal or regulatory proceedings. |
| | o | The ability to effectively integrate the operations and the internal controls of acquired companies. |
| | o | The ability to attract and retain skilled labor and key personnel. |
| | o | 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.
MDU Resources Group, Inc.
| | | Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| (In millions, except per share amounts) | |
| | | (Unaudited) | |
| Operating revenues | | $ | 901.8 | | | $ | 834.8 | |
| | | | | | | | | |
| Operating expenses: | | | | | | | | |
Fuel and purchased power | | | 16.9 | | | | 16.9 | |
Purchased natural gas sold | | | 244.7 | | | | 233.7 | |
Operation and maintenance | | | 427.7 | | | | 376.8 | |
Depreciation, depletion and amortization | | | 84.7 | | | | 78.7 | |
Taxes, other than income | | | 49.7 | | | | 45.8 | |
| | | | 823.7 | | | | 751.9 | |
| | | | | | | | | |
| Operating income | | | 78.1 | | | | 82.9 | |
| | | | | | | | | |
| Earnings from equity method investments | | | .5 | | | | 2.2 | |
| | | | | | | | | |
| Other income | | | 1.9 | | | | 2.5 | |
| | | | | | | | | |
| Interest expense | | | 22.1 | | | | 20.5 | |
| | | | | | | | | |
| Income before income taxes | | | 58.4 | | | | 67.1 | |
| | | | | | | | | |
| Income taxes | | | 15.9 | * | | | 25.3 | |
| | | | | | | | | |
| Income from continuing operations | | | 42.5 | | | | 41.8 | |
| | | | | | | | | |
| Income from discontinued operations, net of tax | | | .5 | | | | --- | |
| | | | | | | | | |
| Net income | | | 43.0 | | | | 41.8 | |
| | | | | | | | | |
| Dividends on preferred stocks | | | .2 | | | | .2 | |
| | | | | | | | | |
| Earnings on common stock | | $ | 42.8 | | | $ | 41.6 | |
| | | | | | | | | |
| Earnings per common share – basic: | | | | | | | | |
Earnings before discontinued operations | | $ | .22 | | | $ | .22 | |
Discontinued operations, net of tax | | | .01 | | | | --- | |
Earnings per common share – basic | | $ | .23 | | | $ | .22 | |
| Earnings per common share – diluted: | | | | | | | | |
Earnings before discontinued operations | | $ | .22 | | | $ | .22 | |
Discontinued operations, net of tax | | | .01 | | | | --- | |
Earnings per common share – diluted | | $ | .23 | | | $ | .22 | |
| Dividends per common share | | $ | .1625 | | | $ | .1575 | |
| Weighted average common shares outstanding – basic | | | 188.7 | | | | 188.0 | |
| Weighted average common shares outstanding – diluted | | | 188.8 | | | | 188.2 | |
* Including the effect of an approximate $4 million benefit related to the favorable resolution of certain tax matters.
| | | Three Months Ended March 31, | |
| | | 2011 | | | 2010 | |
| | | (Unaudited) | |
| Other Financial Data | | | | | | |
| Book value per common share | | $ | 14.16 | | | $ | 13.78 | |
| Market price per common share | | $ | 22.97 | | | $ | 21.58 | |
| Dividend yield (indicated annual rate) | | | 2.8 | % | | | 2.9 | % |
| Price/earnings ratio* | | | 17.9 | x | | | 15.4 | x |
| Market value as a percent of book value | | | 162.2 | % | | | 156.6 | % |
| Return on average common equity* | | | 9.1 | % | | | 10.5 | % |
| Total assets** | | $ | 6.2 | | | $ | 6.0 | |
| Total equity** | | $ | 2.7 | | | $ | 2.6 | |
| Total debt** | | $ | 1.4 | | | $ | 1.5 | |
| Capitalization ratios: | | | | | | | | |
Total equity | | | 65 | % | | | 63 | % |
Total debt | | | 35 | | | | 37 | |
| | | | 100 | % | | | 100 | % |
| | | | | | | | | |
| | * Represents 12 months ended |
