Mdu resources reports third quarter earnings
Bismarck, n.d.--(business wire)--mdu resources group, inc. (nyse:mdu) today reported third quarter consolidated earnings of $63.8 million, or 34 cents per common share, compared with $60.8 million, or 32 cents per common share for the third quarter of 2010. “we are pleased our diversified business strategy continues to demonstrate its value in a challenging economy,” said terry d. hildestad, president and chief executive officer of mdu resources. “our businesses are operating well, and more important, they are keeping us financially strong so that we can invest in future growth. we have a strong balance sheet, good liquidity and credit rating, healthy cash flows, and are paying a competitive dividend. “we are investing approximately $3.5 billion over the next five years, much of it in projects that are already under way, to increase production and expand our ability to serve key markets. as a result, we expect to be in a very competitive position when the economy strengthens,” he said. for the third quarter the company’s exploration and production business, fidelity, reported earnings of $22.5 million compared to $18.7 million in the same period last year. oil production increased 13 percent over the prior year while natural gas production declined 8 percent, reflecting the company’s progress in increasing liquids as a percentage of overall production. oil production represented 33 percent of total production this quarter, up from 28 percent a year ago. the company expects to have six rigs deployed by year end, up from two at the beginning of the year, with a target of 10 rigs by the end of 2012. average realized natural gas prices declined 9 percent compared to the third quarter of 2010, but were offset by a 27 percent increase in average realized oil prices. the pipeline and energy services business reported earnings of $5.2 million, compared to a third quarter 2010 loss of $7.4 million that resulted from a one-time arbitration charge. following two consecutive years of record storage volumes, the average storage balance declined significantly. total throughput decreased 13 percent in the third quarter compared with last year, primarily the result of lower volumes transported to storage and lower gathering volumes. the electric and natural gas utility continues to perform well reporting a normal natural gas operations third quarter seasonal loss. the loss of $2.9 million reflects higher operation and maintenance expenses, largely related to increased employee benefit plan costs of $2.6 million (after tax) tied to the performance of the markets, which experienced significant volatility during the quarter. excluding this item, operation and maintenance costs were lower for the quarter compared to last year. on a year-to-date basis, the utility business increased earnings by 12 percent compared to the nine months ended sept. 30, 2010. the construction materials and contracting business had earnings of $33.1 million compared to $40.3 million in the third quarter last year. contributing to lower earnings were the effects resulting from the minnesota state government shutdown in july of approximately $3 million, as well as weather related delays early in the quarter, and lower margins including asphalt oil margins. work backlog at sept. 30 was relatively level with that of one year ago. the construction services business reported earnings of $5.1 million. the company’s equipment sales and rental business, which specializes in equipment used in electric transmission construction, continued to report strong sales. this group’s backlog at sept. 30 was $331 million, remaining relatively steady with work backlog levels over the past year. conference call the company will webcast its third quarter earnings conference call nov. 1 beginning at 11 a.m. edt; the call will be accessible at www.mdu.com. a webcast replay and audio replay will be available. the dial-in number for audio replay is (855) 859-2056, or (404) 537-3406 for international callers, conference id 12946239. 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 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. 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. (7 .4)* .9 ( .1) * reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax). 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 $1.15. 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 $515 million. the company expects the 2011 estimated capital expenditures to be funded in its entirety with cash flow generated from operations. exploration and production note: oil includes crude oil, condensate and natural gas liquids. the natural gas and oil production segment reported quarterly earnings of $22.5 million, compared to $18.7 million in 2010. this earnings increase reflects higher average realized oil prices of 27 percent and increased oil production of 13 percent. these increases were partially offset by lower average realized natural gas prices of 9 percent, increased depreciation, depletion and amortization expense, decreased natural gas production of 8 percent, as well as higher production and property taxes. the following information highlights the key growth strategies, projections and certain assumptions for this segment: capital expenditures in 2011 are expected to be approximately $300 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, because of recent improved results in the bakken and south texas areas, the company has increased its forecasted production and now expects a 4 percent to 7 percent increase in oil production offset by a 7 percent to 10 percent decrease in natural gas production. the projected decline in natural gas production is primarily the result of the deferral of certain gas development activity because of sustained low natural gas prices. the company has a total of 5 drilling rigs deployed on its acreage in the bakken, niobrara, south texas and big horn areas. expectations are to add another rig in the fourth quarter. by year-end 2012, the company expects to have approximately 10 rigs deployed on its acreage. bakken – 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 15 operated and participation in various non-operated wells is expected for this year with approximately $60 million of capital expenditures. plans include drilling 17 wells or more annually in 2012 and 2013. over 50 future gross well sites have been identified. estimated gross ultimate recovery per well is 250,000 to 500,000 bbls. the company owns approximately 16,000 net acres of leaseholds targeting the middle bakken and three forks formations. the drilling of 15 operated and participation in various non-operated wells is expected for this year with approximately $60 million of capital expenditures. plans include drilling 17 wells or more annually in 2012 and 2013. over 50 future gross well sites have been identified. estimated gross ultimate recovery per well is 250,000 to 500,000 bbls. bakken – stark county, north dakota the company holds approximately 50,000 net exploratory leasehold acres, targeting the three forks formation. the company has commenced drilling and expects to drill 3 operated wells on this acreage over the next several months and to participate in various non-operated wells with capital of approximately $30 million this year. based on well results, the company plans to drill 6 or more wells annually beginning in 2012. based on 640-acre spacing, the acreage holds over 140 potential gross well sites. estimated gross ultimate recovery rates per well are 250,000 to 400,000 bbls. the company holds approximately 50,000 net exploratory leasehold acres, targeting the three forks formation. the company has commenced drilling and expects to drill 3 operated wells on this acreage over the next several months and to participate in various non-operated wells with capital of approximately $30 million this year. based on well results, the company plans to drill 6 or more wells annually beginning in 2012. based on 640-acre spacing, the acreage holds over 140 potential gross well sites. estimated gross ultimate recovery rates per well are 250,000 to 400,000 bbls. bakken – richland county, montana the company holds approximately 20,000 net exploratory leasehold acres, targeting the three forks formation. approximately 100 potential gross well sites have been identified on this acreage. estimated gross ultimate recovery rates per well are 250,000 to 400,000 bbls. expect to spud first appraisal well in early 2012. the company holds approximately 20,000 net exploratory leasehold acres, targeting the three forks formation. approximately 100 potential gross well sites have been identified on this acreage. estimated gross ultimate recovery rates per well are 250,000 to 400,000 bbls. expect to spud first appraisal well in early 2012. niobrara – southeastern wyoming the company holds approximately 65,000 net exploratory leasehold acres in this emerging oil play. appraisal well drilling has begun with a total of 4 wells planned during the next several months. if successful, the company plans to initiate a drilling program of approximately 8 wells annually starting in 2012. the company also expects to participate in various non-operated wells in the niobrara. although this is an emerging exploratory play, the company estimates it has as many as 200 potential future gross wells on this acreage based on 640-acre spacing. estimated gross ultimate recovery rates per well are 200,000 to 300,000 bbls. the company holds approximately 65,000 net exploratory leasehold acres in this emerging oil play. appraisal well drilling has begun with a total of 4 wells planned during the next several months. if successful, the company plans to initiate a drilling program of approximately 8 wells annually starting in 2012. the company also expects to participate in various non-operated wells in the niobrara. although this is an emerging exploratory play, the company estimates it has as many as 200 potential future gross wells on this acreage based on 640-acre spacing. estimated gross ultimate recovery rates per well are 200,000 to 300,000 bbls. paradox basin – cane creek federal unit, utah the company holds approximately 75,000 net exploratory leasehold acres. the company expects to drill 2 wells in the next six months. potential future gross wells are estimated at 70. estimated gross ultimate recovery rates per well are 250,000 to 500,000 bbls. the company holds approximately 75,000 net exploratory leasehold acres. the company expects to drill 2 wells in the next six months. potential future gross wells are estimated at 70. estimated gross ultimate recovery rates per well are 250,000 to 500,000 bbls. texas the company is targeting areas that have the potential for higher liquids content with approximately $50 million of capital planned for this year. plans are to drill approximately 12 wells in total this year in south texas. the company has identified 50 future potential gross well sites. estimated gross ultimate recovery rates per well are 250,000 to 400,000 bbls. the company is targeting areas that have the potential for higher liquids content with approximately $50 million of capital planned for this year. plans are to drill approximately 12 wells in total this year in south texas. the company has identified 50 future potential gross well sites. estimated gross ultimate recovery rates per well are 250,000 to 400,000 bbls. other opportunities the company holds approximately 80,000 net exploratory leasehold acres in the heath shale oil prospect in montana. plans include drilling 2 appraisal wells over the next six months. the company continues to pursue acquisitions of additional leaseholds. approximately $50 million of capital has been allocated to leasehold acquisitions this year, focusing on expansion of existing positions and new opportunities. the company holds approximately 80,000 net exploratory leasehold acres in the heath shale oil prospect in montana. plans include drilling 2 appraisal wells over the next six months. the company continues to pursue acquisitions of additional leaseholds. approximately $50 million of capital has been allocated to leasehold acquisitions this year, focusing on expansion of existing positions and new opportunities. earnings guidance reflects estimated natural gas and oil prices for november and december as follows: natural gas index: crude oil index: for the last three months of 2011, the company has hedged approximately 45 percent to 50 percent of its estimated natural gas production and 60 percent to 65 percent of its estimated oil production. for 2012, it has hedged 25 percent to 30 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 oct. 31 are summarized in the following chart: * 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 * reflects a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax). this segment reported third quarter earnings of $5.2 million, compared to a loss of $7.4 million for the same period in 2010. the earnings increase reflects lower operation and maintenance expense, primarily related to the absence of the natural gas gathering arbitration charge in 2010. partially offsetting this increase was lower storage services revenue, as well as lower gathering volumes. 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. 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 27 mmcf of firm capacity. construction has begun on approximately 12 miles of high pressure transmission pipeline providing takeaway capacity from the garden creek processing facility being constructed in northwestern north dakota. the pipeline project is expected to be completed before year-end. preparations are underway for the construction of approximately 13 miles of high pressure transmission pipeline from the stateline i and ii processing facilities in northwestern north dakota to deliver gas into the northern border pipeline. the project is expected to be completed by mid 2012. the company has three natural gas storage fields including the largest storage field in north america located near baker, montana. it continues to seek 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. commitment on approximately 30 percent of the total potential project has been received. the additional firm deliverability is expected to be available in november. electric and natural gas utilities * degree days are a measure of the daily temperature-related demand for energy for heating. the combined utility businesses reported a loss of $2.9 million, compared to earnings of $1.2 million for the same period in 2010. the decrease in earnings reflects higher operation and maintenance expense, largely benefit-related; higher income taxes; and increased depreciation, depletion and amortization expense. these items were partially offset by increased retail natural gas sales margins. the following information highlights the key growth strategies, projections and certain assumptions for this segment: in august 2010, 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. effective feb. 14, the commission approved an interim increase of $2.6 million annually, or approximately 6.3 percent. the commission approved final rates at the interim increase level for service rendered effective sept. 1. on july 7, the company filed for an advance determination of prudence with the north dakota public service commission 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. an order is expected in first quarter 2012. 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. 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 proposed project totals approximately $20 million and includes substation upgrades. construction is underway and the project is expected to be completed by mid 2012. 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 practicable, but not later than five years after epa’s approval of the state program. the state program was submitted jan. 21. the company’s share of the cost of this air quality control system could exceed $100 million. 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. on may 20, the company filed for an advance determination of prudence with the ndpsc requesting advance determination that the air quality control system is reasonable and prudent. the hearing is scheduled for nov. 29, and an order is expected in early 2012. construction the construction materials and contracting segment reported third quarter earnings of $33.1 million, compared to $40.3 million for the same period in 2010. the decrease in earnings largely resulted from lower asphalt oil, asphalt and construction margins, as well as higher income taxes. lower margins included the effects of the minnesota state government shutdown in july and weather-related delays. partially offsetting the decreases was lower interest expense. the following information highlights the key growth strategies, projections and certain assumptions for this segment: work backlog as of sept. 30 was approximately $448 million, with 91 percent of construction backlog being public work and private representing 9 percent. in the company’s peak earnings year of 2006, private backlog represented 40 percent of construction backlog. backlog a year ago was $464 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 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 has green fielded an operation in williston, north dakota and was awarded a $33 million highway project in the bakken area of north dakota. it also expects to place a new asphalt oil terminal into service by year-end in wyoming. the company is the primary cement provider in hawaii and has the opportunity to supply a portion of the ready-mixed concrete and aggregate related to a multi-phased light rail project. overall 2011 volumes are expected to be comparable to 2010. 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. 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. this segment had third quarter earnings of $5.1 million, compared to $6.0 million a year ago. this decrease reflects lower construction workloads and margins in the mountain region, as well as lower margins in the central region. partially offsetting the earnings decrease were higher equipment sales and rental margins, as well as higher construction workloads and margins in the western region. the following information highlights the key growth strategies, projections and certain assumptions for this segment: work backlog as of sept. 30 was approximately $331 million, compared to $317 million a year ago. the backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work. 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. other 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 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: 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. 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. (in millions, except per share amounts) (unaudited) operating expenses: 19.6 101.9 earnings per common share – basic: note: three months and nine months ended sept. 30, 2010 results reflect the effects of a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax, or $.09 per common share). 15.1 x 16.8 x * represents 12 months ended** in billions
