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| 8-K - MDU RESOURCES GROUP, INC. FORM 8-K - MDU RESOURCES GROUP INC | mdu4302012_8k.htm |
MDU Resources Reports First Quarter Earnings, Reaffirms 2012 Earnings Guidance
• | Consolidated earnings of $35.6 million, or 19 cents per share. |
• | Oil production grows 19%. |
• | Rig count reaches 10, up from 2 a year ago. |
• | Recently announced significant Paradox Basin well test results. |
• | Advance Determination of Prudence approved for natural gas plant. |
BISMARCK, N.D. - April 30, 2012 - MDU Resources Group, Inc. (NYSE:MDU) today reported first quarter consolidated earnings of $35.6 million, or 19 cents per common share, compared to $42.8 million, or 23 cents per common share for the first quarter of 2011. First quarter 2011 earnings include the effect of an approximate $4 million benefit related to the favorable resolution of certain tax matters.
“We achieved the upper range of our guidance for the quarter, even though we experienced some weather and pricing challenges,” said Terry D. Hildestad, president and chief executive officer of MDU Resources. “That is a good indication of the strength of our diversified business and a solid base on which to continue building our estimated $3.7 billion capital growth program over the next five years.
“Our exploration and production business is well on the way toward its 2012 target of increasing oil production by 20 percent to 30 percent over last year,” he said. “Led primarily by growth at Fidelity's Bakken operations, overall oil production increased to approximately 10,500 barrels per day in the first quarter, a 19 percent increase from the same period a year earlier.”
Fidelity currently is operating 10 rigs, eight more than a year ago. Five are working in the Bakken, where the company holds approximately 124,000 net leasehold acres, including an additional 27,000 Richland County acres that were acquired earlier in the first quarter. The company plans to invest approximately 40 percent of its $400 million capital budget in its Bakken acreage this year.
Hildestad said that Fidelity is seeing some improvement in Bakken wellhead oil pricing spreads compared to WTI prices. The price spread widened in March and negatively affected first quarter earnings but narrowed in April, and forecasts indicate continued improvement throughout 2012. Fidelity also was affected by average realized natural gas prices that were 32 percent lower than the first quarter of 2011.
“In addition, we are excited about the recently announced significant appraisal well results in the Paradox Basin where we own 75,000 net leasehold acres,” Hildestad said. “The potential of this play appears substantial. The Cane Creek Unit No. 26-2H well was tested at a stabilized rate of 647 barrels of oil per day and 561 thousand cubic feet of natural gas per day following two weeks of production. These results are based on a significantly restricted flow allowing our team to properly manage production operations, gather performance data and minimize natural gas flaring.”
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Natural gas prices are at a 10-year low and the company's dry natural gas properties are held by production. The company believes it has been prudent in curtailing natural gas production in an over-supplied market and instead focusing on its substantial liquids-based opportunities.
Natural gas prices also had an effect on the pipeline and energy services business, which experienced decreased storage and gathering volumes. Total transportation volumes increased, principally related to completion of a new pipeline to move natural gas from a third-party processing plant that began operating in December. In addition to a proposed diesel topping facility, the pipeline business continues to explore opportunities in other liquid-based midstream projects.
Significantly warmer weather affected sales at the utility business segment. Natural gas sales volumes declined 12 percent, with temperatures nearly 31 percent warmer than the prior year in the Plains states service territory and 11 percent warmer in Idaho. The North Dakota Public Service Commission recently approved a request for advance determination of prudence for an 88-MW, approximate $85 million natural gas generation facility that the company plans to build in North Dakota, part of the utility's approximate $915 million five-year capital growth program.
The construction business continued to see signs of stabilization in the construction market. Earnings at the construction services business increased to $11.4 million compared to $4.6 million a year ago, driven by higher construction revenue and margins and higher equipment sales and rental. Although the construction materials segment experienced a normal seasonal loss, we are optimistic about the prospects for earnings from prior green fielded operations in Cheyenne and the Bakken region.
“Our businesses are making good progress in executing their 2012 plans,” Hildestad said. “We are off to a good start on the year.”
Based on the company's projections for the remainder of 2012, annual earnings guidance is reaffirmed in the range of $1.00 to $1.25 per share.
The company will host a webcast at 11 a.m. EDT on Tuesday, May 1 to discuss earnings results and guidance. 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 66804286.
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 companies. 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
Laura Lueder, corporate public relations manager, (701) 530-1095
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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 2012 (In Millions) | Earnings First Quarter 2011 (In Millions) | ||||||
Exploration and Production | $12.9 | $16.3 | ||||||
Regulated | ||||||||
Electric and natural gas utilities | 33.0 | 36.0 | ||||||
Pipeline and energy services | 2.8 | 6.9 | ||||||
Construction | ||||||||
Construction materials and contracting | (24.9 | ) | (21.4 | ) | ||||
Construction services | 11.4 | 4.6 | ||||||
Other | .5 | (.1 | ) | |||||
Earnings before discontinued operations | 35.7 | 42.3 | ||||||
Income (loss) from discontinued operations, net of tax | (.1 | ) | .5 | |||||
Earnings on common stock | $35.6 | $42.8 | * | |||||
* Includes the effect of an approximate $4 million benefit related to the favorable resolution of certain tax matters.
On a consolidated basis, the following information highlights the key growth strategies, projections and certain assumptions for the company:
• | Earnings per common share for 2012, diluted, are projected in the range of $1.00 to $1.25. The company expects the approximate percentage of 2012 earnings per common share by quarter to be: |
• | Second quarter - 15 percent |
• | Third quarter - 35 percent |
• | Fourth quarter - 30 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 2012 are approximately $700 million. |
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Exploration and Production
Three Months Ended | ||||||
March 31, | ||||||
2012 | 2011 | |||||
(Dollars in millions, where applicable) | ||||||
Operating revenues: | ||||||
Oil | $ | 73.4 | $ | 58.6 | ||
Natural gas | 26.4 | 45.4 | ||||
99.8 | 104.0 | |||||
Operating expenses: | ||||||
Operation and maintenance: | ||||||
Lease operating costs | 18.5 | 18.0 | ||||
Gathering and transportation | 4.3 | 5.7 | ||||
Other | 9.2 | 8.3 | ||||
Depreciation, depletion and amortization | 36.8 | 34.2 | ||||
Taxes, other than income: | ||||||
Production and property taxes | 9.5 | 10.1 | ||||
Other | .4 | .3 | ||||
78.7 | 76.6 | |||||
Operating income | 21.1 | 27.4 | ||||
Earnings | $ | 12.9 | $ | 16.3 | ||
Production: | ||||||
Oil (MBbls) | 957 | 802 | ||||
Natural gas (MMcf) | 10,047 | 11,758 | ||||
Total production (MBOE) | 2,632 | 2,762 | ||||
Average realized prices (including hedges): | ||||||
Oil (per barrel) | $ | 76.71 | $ | 72.98 | ||
Natural gas (per Mcf) | $ | 2.63 | $ | 3.86 | ||
Average realized prices (excluding hedges): | ||||||
Oil (per barrel) | $ | 84.62 | $ | 79.24 | ||
Natural gas (per Mcf) | $ | 1.94 | $ | 3.39 | ||
Average depreciation, depletion and amortization rate, per BOE | $ | 13.32 | $ | 11.76 | ||
Production costs, including taxes, per BOE: | ||||||
Lease operating costs | $ | 7.02 | $ | 6.52 | ||
Gathering and transportation | 1.63 | 2.05 | ||||
Production and property taxes | 3.62 | 3.65 | ||||
$ | 12.27 | $ | 12.22 | |||
Notes: • Oil includes crude oil, condensate and natural gas liquids. • Beginning with first quarter results, reporting barrel of oil equivalents rather than million cubic feet equivalents, based on a 6:1 ratio. | ||||||
Earnings at this segment were $12.9 million for the first quarter of 2012, compared to $16.3 million in 2011. This decrease reflects 32 percent lower average realized natural gas prices, decreased natural gas production of 15 percent, as well as higher depreciation, depletion and amortization expense. These decreases were partially offset by increased oil production of 19 percent and 5 percent higher average realized oil prices. The combined oil and natural gas pricing earnings effect was a negative $6.5 million.
The following information highlights the key growth strategies, projections and certain assumptions for
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this segment:
• | The company expects to spend approximately $400 million in capital expenditures in 2012. The company continues its focus on returns by allocating the majority 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 2012 planned capital expenditure total does not include potential acquisitions of producing properties. |
• | For 2012, the company expects a 20 percent to 30 percent increase in oil production and a 12 percent to 20 percent decrease in natural gas production. The projected decline in natural gas production is primarily the result of the divestment and/or curtailment of certain natural gas properties and the deferral of certain natural gas development activity because of sustained low natural gas prices. |
• | The company has a total of 10 drilling rigs deployed on its acreage in the Bakken, Texas, Paradox, Heath Shale and other areas. Eight rigs were deployed at year end. Dependent upon results during 2012, further growth in rig activity could occur. |
• | Bakken Area |
◦ | The company owns a total of approximately 124,000 net acres of leaseholds. |
◦ | Capital expenditures are expected to total approximately $160 million this year; approximately $60 million higher than the capital spent for 2011. |
◦ | Mountrail County, North Dakota |
▪ | The company owns approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations. |
▪ | The drilling of 17 operated wells and participation in various non-operated wells is expected for this year with approximately $75 million of capital expenditures. |
▪ | Over 50 future gross well sites have been identified. Estimated gross ultimate recovery per well is 250,000 to 500,000 Bbls. |
◦ | Stark County, North Dakota |
▪ | The company holds approximately 51,000 net exploratory leasehold acres, targeting the Three Forks formation. |
▪ | The drilling of 7 operated wells and participation in various non-operated wells is expected for this year with approximately $60 million of capital expenditures. |
▪ | Based on 640-acre spacing, approximately 140 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
◦ | Richland County, Montana |
▪ | The company has increased its acreage to approximately 57,000 net exploratory leasehold acres, targeting the Three Forks formation. |
▪ | The drilling of 5 operated wells is planned for this year with approximately $25 million of capital expenditures. |
▪ | Approximately 100 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
• | Niobrara - southeastern Wyoming |
◦ | The company holds approximately 65,000 net exploratory leasehold acres. |
◦ | The drilling of 4 operated wells is expected for this year with approximately $25 million of capital expenditures. |
◦ | Approximately 200 potential gross well sites are available based on 640-acre spacing. |
• | Paradox Basin - Cane Creek Federal Unit, Utah |
◦ | The company holds approximately 75,000 net exploratory leasehold acres. |
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◦ | The company is evaluating its potential in the area and anticipates increasing the number of wells to be drilled this year considering recently announced appraisal well results. |
◦ | Approximately 70 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well range from 250,000 to 1,000,000 Bbls. |
• | Texas |
◦ | The company is targeting areas that have the potential for higher liquids content with approximately $60 million of capital planned for this year. |
◦ | Plans are to drill 20 operated wells in Texas this year. |
◦ | Approximately 50 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls. |
• | Heath Shale |
◦ | The company holds approximately 90,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana and expects to drill 4 wells this year with capital of approximately $20 million. |
• | Other Opportunities |
◦ | The company continues to pursue acquisitions of additional leaseholds. Approximately $25 million of capital has been allocated to leasehold acquisitions, focusing on expansion of existing positions and new opportunities. |
◦ | The remaining forecasted 2012 capital has been allocated to other operated and non-operated opportunities. |
• | Earnings guidance reflects estimated oil and natural gas prices for May through December as follows: |
Crude Oil Index: NYMEX | $95 to $105 per barrel |
Natural Gas Index: NYMEX | $2.25 to $2.75 per Mcf |
Note: Estimated prices do not reflect potential basis differentials.
• | For the last nine months of 2012, the company has hedged approximately 60 percent to 65 percent of its estimated oil production and 35 percent to 40 percent of its estimated natural gas production. For 2013, the company has hedged 30 percent to 35 percent of its estimated oil production. The hedges that are in place as of April 30 are summarized in the following chart: |
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Commodity | Type | Index | Period Outstanding | Forward Notional Volume (Bbl/MMBtu) | Price (Per Bbl/MMBtu) |
Crude Oil | Collar | NYMEX | 4/12 - 12/12 | 275,000 | $80.00-$87.80 |
Crude Oil | Collar | NYMEX | 4/12 - 12/12 | 275,000 | $80.00-$94.50 |
Crude Oil | Collar | NYMEX | 4/12 - 12/12 | 275,000 | $80.00-$98.36 |
Crude Oil | Collar | NYMEX | 4/12 - 12/12 | 137,500 | $85.00-$102.75 |
Crude Oil | Collar | NYMEX | 4/12 - 12/12 | 137,500 | $85.00-$103.00 |
Crude Oil | Swap | NYMEX | 4/12 - 12/12 | 137,500 | $100.10 |
Crude Oil | Swap | NYMEX | 4/12 - 12/12 | 137,500 | $100.00 |
Crude Oil | Swap | NYMEX | 4/12 - 12/12 | 275,000 | $110.30 |
Crude Oil | Swap | NYMEX | 4/12 - 12/12 | 275,000 | $96.00 |
Crude Oil | Swap | NYMEX | 4/12 - 12/12 | 275,000 | $99.00 |
Natural Gas | Swap | NYMEX | 4/12 - 12/12 | 2,612,500 | $6.27 |
Natural Gas | Swap | NYMEX | 4/12 - 12/12 | 1,375,000 | $5.005 |
Natural Gas | Swap | NYMEX | 4/12 - 12/12 | 687,500 | $5.005 |
Natural Gas | Swap | NYMEX | 4/12 - 12/12 | 687,500 | $5.0125 |
Natural Gas | Swap | NYMEX | 4/12 - 12/12 | 2,750,000 | $3.05 |
Natural Gas | Swap | Ventura | 4/12 - 12/12 | 2,750,000 | $4.87 |
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 |
Crude Oil | Collar | NYMEX | 1/13 - 12/13 | 365,000 | $90.00-$97.05 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $95.00 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $95.30 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $100.00 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $100.02 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $102.00 |
Crude Oil | Swap | NYMEX | 1/13 - 12/13 | 182,500 | $102.00 |
Natural Gas | Basis Swap | CIG | 4/12 - 12/12 | 2,062,500 | $0.405 |
Natural Gas | Basis Swap | CIG | 4/12 - 12/12 | 550,000 | $0.41 |
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. • For all basis swaps, index prices are below NYMEX prices and are reported as a positive amount in the price column. | |||||
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Regulated
Electric and Natural Gas Utilities
Electric | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2012 | 2011 | |||||
(Dollars in millions, where applicable) | ||||||
Operating revenues | $ | 58.0 | $ | 57.8 | ||
Operating expenses: | ||||||
Fuel and purchased power | 18.4 | 16.9 | ||||
Operation and maintenance | 16.2 | 16.0 | ||||
Depreciation, depletion and amortization | 8.1 | 8.2 | ||||
Taxes, other than income | 2.7 | 2.5 | ||||
45.4 | 43.6 | |||||
Operating income | 12.6 | 14.2 | ||||
Earnings | $ | 7.5 | $ | 8.5 | ||
Retail sales (million kWh) | 769.7 | 794.7 | ||||
Sales for resale (million kWh) | 1.9 | 6.7 | ||||
Average cost of fuel and purchased power per kWh | $ | .022 | $ | .020 | ||
Natural Gas Distribution | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2012 | 2011 | |||||
(Dollars in millions) | ||||||
Operating revenues | $ | 307.9 | $ | 370.4 | ||
Operating expenses: | ||||||
Purchased natural gas sold | 199.3 | 257.5 | ||||
Operation and maintenance | 35.3 | 34.4 | ||||
Depreciation, depletion and amortization | 11.2 | 11.1 | ||||
Taxes, other than income | 16.1 | 17.7 | ||||
261.9 | 320.7 | |||||
Operating income | 46.0 | 49.7 | ||||
Earnings | $ | 25.5 | $ | 27.5 | ||
Volumes (MMdk): | ||||||
Sales | 38.7 | 43.9 | ||||
Transportation | 37.9 | 34.1 | ||||
Total throughput | 76.6 | 78.0 | ||||
Degree days (% of normal)* | ||||||
Montana-Dakota | 77 | % | 111 | % | ||
Cascade | 101 | % | 103 | % | ||
Intermountain | 93 | % | 105 | % | ||
* Degree days are a measure of the daily temperature-related demand for energy for heating. | ||||||
The combined utility businesses reported earnings of $33.0 million in the first quarter of 2012, compared to earnings of $36.0 million for the same period in 2011. This decrease reflects decreased natural gas retail
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sales volumes with an approximate earnings affect of $2.6 million, resulting from warmer weather than last year, lower electric retail sales volumes as well as higher income taxes, primarily related to the absence of an income tax benefit of $1.1 million related to favorable resolution of certain income tax matters in 2011.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
• | The EPA approved the South Dakota Regional Haze Program on March 29 which requires 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. The company's share of the cost of this air quality control system is estimated at $125 million. The company intends to seek recovery of costs related to the above matter in electric rates charged to customers. The company expects an order for an advance determination of prudence from the North Dakota Public Service Commission in the second quarter. |
• | On July 7 the company filed for an advance determination of prudence with the NDPSC on the construction of an 88-MW simple cycle natural gas turbine and associated facilities projected to be in service in 2015. The turbine will be located on currently owned property that is adjacent to the company's Heskett Generating Station near Mandan, North Dakota and is necessary to meet the capacity requirements of the company's integrated electric system customers. The capacity will be a partial replacement for third party contract capacity expiring in 2015. Project cost is estimated to be $85.6 million. On April 11 the commission issued an order approving the advance determination of prudence. |
• | 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 currently served by fuel oil or propane, and to serve new customers. A project the company is currently engaged on is a 30-mile natural gas line into the Hanford Nuclear Site in Washington. |
• | Currently the company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest. |
• | 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 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 company's portion of the project totals approximately $18 million and includes substation upgrades. Construction is underway and the transmission project is expected to be completed by the third quarter. |
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Pipeline and Energy Services | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2012 | 2011 | |||||
(Dollars in millions) | ||||||
Operating revenues | $ | 49.6 | $ | 74.0 | ||
Operating expenses: | ||||||
Purchased natural gas sold | 16.0 | 34.1 | ||||
Operation and maintenance | 17.1 | 17.6 | ||||
Depreciation, depletion and amortization | 6.2 | 6.4 | ||||
Taxes, other than income | 3.5 | 3.6 | ||||
42.8 | 61.7 | |||||
Operating income | 6.8 | 12.3 | ||||
Earnings | $ | 2.8 | $ | 6.9 | ||
Transportation volumes (MMdk) | 32.0 | 27.3 | ||||
Gathering volumes (MMdk) | 14.2 | 17.5 | ||||
Customer natural gas storage balance (MMdk): | ||||||
Beginning of period | 36.0 | 58.8 | ||||
Net withdrawal | (8.7 | ) | (25.9 | ) | ||
End of period | 27.3 | 32.9 | ||||
This segment reported first quarter earnings of $2.8 million, compared to earnings of $6.9 million for the same period in 2011. This decrease reflects lower storage services revenue, lower gathering volumes, as well as the absence of an income tax benefit of $500,000 related to favorable resolution of certain income tax matters in 2011.
The following information highlights the key growth strategies, projections and certain assumptions for this segment:
• | In February, the company and Calumet Refining, LLC signed a letter of intent to explore the feasibility of jointly building and operating a 20,000 barrel per day diesel topping plant in southwestern North Dakota. The facility would process Bakken crude and market the diesel within the Bakken region. Site selection, permitting, crude oil feed procurement, marketing and engineering studies are currently underway. |
• | The company has recently seen an uptick in natural gas moving to storage and expects average balances for the remainder of the year to be comparable to last year. The divestment and/or curtailment of certain natural gas properties and the deferral of certain gas development activity are expected to result in gathering volumes being lower in 2012 compared to last year. The decline is expected to be partially offset by higher transportation volumes related to growth projects placed in service in the Bakken area. |
• | 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. 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. |
• | Installation of additional compression at the Charbonneau station was completed and placed into service in September, providing additional firm capacity for producers in the Bakken production area. With some additional modifications, this project has the potential of adding a total of |
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27 MMcf of firm capacity.
• | Construction has begun on approximately 13 miles of high pressure transmission pipeline from the Stateline processing facilities in northwestern North Dakota to deliver gas into the Northern Border Pipeline. The project is expected to be completed by mid 2012. |
Construction
Construction Materials and Contracting | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2012 | 2011 | |||||
(Dollars in millions) | ||||||
Operating revenues | $ | 149.4 | $ | 143.5 | ||
Operating expenses: | ||||||
Operation and maintenance | 157.0 | 146.8 | ||||
Depreciation, depletion and amortization | 19.8 | 21.5 | ||||
Taxes, other than income | 8.0 | 7.7 | ||||
184.8 | 176.0 | |||||
Operating loss | (35.4 | ) | (32.5 | ) | ||
Loss | $ | (24.9 | ) | $ | (21.4 | ) |
Sales (000's): | ||||||
Aggregates (tons) | 2,493 | 2,827 | ||||
Asphalt (tons) | 100 | 165 | ||||
Ready-mixed concrete (cubic yards) | 468 | 397 | ||||
Construction Services | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2012 | 2011 | |||||
(In millions) | ||||||
Operating revenues | $ | 218.2 | $ | 203.4 | ||
Operating expenses: | ||||||
Operation and maintenance | 187.9 | 184.9 | ||||
Depreciation, depletion and amortization | 2.8 | 2.9 | ||||
Taxes, other than income | 7.8 | 7.7 | ||||
198.5 | 195.5 | |||||
Operating income | 19.7 | 7.9 | ||||
Earnings | $ | 11.4 | $ | 4.6 | ||
The combined construction businesses reported a first quarter loss of $13.5 million, compared to a loss of $16.8 million a year ago. The decreased loss reflects a $6.8 million earnings increase at the services group that resulted from higher workloads and margins in the Central and Western regions and higher equipment sales and rental and Mountain region margins. Partially offsetting the service group's increased earnings was a seasonal loss at the materials group including lower aggregate margins and volumes. In addition, the construction businesses on a combined basis had an increase in income taxes primarily related to the absence of an income tax benefit of $2.5 million related to favorable resolution of certain income tax matters in 2011.
The following information highlights the key growth strategies, projections and certain assumptions for the construction segments:
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• | The construction materials work backlog as of March 31 was approximately $532 million, compared to approximately $569 million a year ago. The March 31 backlog at construction services was approximately $333 million, compared to approximately $347 million a year ago. The backlog includes 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 operations in the prolific Bakken area of North Dakota currently have approximately $35 million of backlog. |
• | Projected revenues included in the company's 2012 earnings guidance are in the range of $1.3 billion to $1.4 billion for construction materials and $750 million to $850 million for construction services. |
• | The company anticipates margins in 2012 to be higher than 2011 levels at construction materials and construction services. |
• | 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 expansion into new markets. |
• | As the country's 5th 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 March 31, | ||||||
2012 | 2011 | |||||
(In millions) | ||||||
Operating revenues | $ | 2.1 | $ | 2.5 | ||
Operating expenses: | ||||||
Operation and maintenance | 1.3 | 2.9 | ||||
Depreciation, depletion and amortization | .5 | .4 | ||||
Taxes, other than income | — | .1 | ||||
1.8 | 3.4 | |||||
Operating income (loss) | .3 | (.9 | ) | |||
Income (loss) from continuing operations | .5 | (.1 | ) | |||
Income (loss) from discontinued operations, net of tax | (.1 | ) | .5 | |||
Earnings | $ | .4 | $ | .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 exploration and 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. |
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• | 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 materials and contracting and construction services 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. |
• | Initiatives to reduce greenhouse gas emissions could adversely impact the company’s electric generation 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. |
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◦ | 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.
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MDU Resources Group, Inc. | |||||||
Three Months Ended | |||||||
March 31, | |||||||
2012 | 2011 | ||||||
(In millions, except per share amounts) | |||||||
(Unaudited) | |||||||
Operating revenues | $ | 852.8 | $ | 901.8 | |||
Operating expenses: | |||||||
Fuel and purchased power | 18.4 | 16.9 | |||||
Purchased natural gas sold | 185.4 | 244.7 | |||||
Operation and maintenance | 444.5 | 427.7 | |||||
Depreciation, depletion and amortization | 85.4 | 84.7 | |||||
Taxes, other than income | 48.0 | 49.7 | |||||
781.7 | 823.7 | ||||||
Operating income | 71.1 | 78.1 | |||||
Earnings from equity method investments | 1.2 | .5 | |||||
Other income | 1.1 | 1.9 | |||||
Interest expense | 19.4 | 22.1 | |||||
Income before income taxes | 54.0 | 58.4 | |||||
Income taxes | 18.1 | 15.9 | * | ||||
Income from continuing operations | 35.9 | 42.5 | |||||
Income (loss) from discontinued operations, net of tax | (.1 | ) | .5 | ||||
Net income | 35.8 | 43.0 | |||||
Dividends declared on preferred stocks | .2 | .2 | |||||
Earnings on common stock | $ | 35.6 | $ | 42.8 | |||
Earnings per common share – basic: | |||||||
Earnings before discontinued operations | $ | .19 | $ | .22 | |||
Discontinued operations, net of tax | — | .01 | |||||
Earnings per common share – basic | $ | .19 | $ | .23 | |||
Earnings per common share – diluted: | |||||||
Earnings before discontinued operations | $ | .19 | $ | .22 | |||
Discontinued operations, net of tax | — | .01 | |||||
Earnings per common share – diluted | $ | .19 | $ | .23 | |||
Dividends declared per common share | $ | .1675 | $ | .1625 | |||
Weighted average common shares outstanding – basic | 188.8 | 188.7 | |||||
Weighted average common shares outstanding – diluted | 189.2 | 188.8 | |||||
* Including the effect of an approximate $4 million benefit related to the favorable resolution of certain tax matters.
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Three Months Ended March 31, | |||||||
2012 | 2011 | ||||||
(Unaudited) | |||||||
Other Financial Data | |||||||
Book value per common share | $ | 14.61 | $ | 14.16 | |||
Market price per common share | $ | 22.39 | $ | 22.97 | |||
Dividend yield (indicated annual rate) | 3.0 | % | 2.8 | % | |||
Price/earnings ratio* | 20.7x | 17.9x | |||||
Market value as a percent of book value | 153.3 | % | 162.2 | % | |||
Return on average common equity* | 7.5 | % | 9.1 | % | |||
Total assets** | $ | 6.5 | $ | 6.2 | |||
Total equity** | $ | 2.8 | $ | 2.7 | |||
Total debt ** | $ | 1.4 | $ | 1.4 | |||
Capitalization ratios: | |||||||
Total equity | 66 | % | 65 | % | |||
Total debt | 34 | 35 | |||||
100 | % | 100 | % | ||||
* Represents 12 months ended
** In billions
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