Item 1A - Risk Factors.
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
The Company is a diversified natural resource company, which was incorporated under the laws of the state of Delaware in 1924. Its principal executive offices are at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650, telephone (701) 530-1000.
Montana-Dakota, through the electric and natural gas distribution segments, generates, transmits and distributes electricity and distributes natural gas in Montana, North Dakota, South Dakota and Wyoming. Cascade distributes natural gas in Washington and Oregon. Intermountain distributes natural gas in Idaho. Great Plains distributes natural gas in western Minnesota and southeastern North Dakota. These operations also supply related value-added products and services.
The Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings (comprised of the pipeline and energy services and the natural gas and oil production segments), Knife River (construction materials and contracting segment), MDU Construction Services (construction services segment), Centennial Resources and Centennial Capital (both reflected in the Other category).
The Company's equity method investment in the Brazilian Transmission Lines, as discussed in Item 8 - Note ­­4, is reflected in the Other category.
As of December 31, 2008, the Company had 10,074 employees with 156 employed at MDU Resources Group, Inc., 896 at Montana-Dakota, 35 at Great Plains, 377 at Cascade, 339 at Intermountain, 609 at WBI Holdings, 3,059 at Knife River, 4,600 at MDU Construction Services and three at Centennial Resources. The number of employees at certain Company operations fluctuates during the year depending upon the number and size of construction projects. The Company considers its relations with employees to be satisfactory.
At Montana-Dakota and Williston Basin, 421 and 80 employees, respectively, are represented by the IBEW. Labor contracts with such employees are in effect through May 30, 2011, and March 31, 2011, for Montana-Dakota and Williston Basin, respectively.
At Cascade, 212 employees are represented by the ICWU. The labor contract with the field operations group, consisting of 177 employees extends to April 1, 2009, and remains in force thereafter from year to year unless terminated by either party. Cascade has received notice from the ICWU of their desire to meet and bargain a new agreement. Cascade is in the process of negotiating an agreement with the bargaining unit consisting of 35 customer service representatives and credit and collections clerks.
At Intermountain, 114 employees are represented by the UA. Labor contracts with such employees are in effect through September 30, 2010.
Knife River has 43 labor contracts that represent approximately 400 of its construction materials employees. Knife River is in negotiations on two of its labor contracts.
MDU Construction Services has 126 labor contracts representing the majority of its employees. The majority of the labor contracts contain provisions that prohibit work stoppages or strikes and provide for binding arbitration dispute resolution in the event of an extended disagreement.
The Company's principal properties, which are of varying ages and are of different construction types, are generally in good condition, are well maintained and are generally suitable and adequate for the purposes for which they are used.
The financial results and data applicable to each of the Company's business segments, as well as their financing requirements, are set forth in Item 7 - MD&A and Item 8 - Note ­­16 and Supplementary Financial Information.
The operations of the Company and certain of its subsidiaries are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations and state hazard communication standards. The Company believes that it is in substantial compliance with these regulations, except as to what may be ultimately determined with regard to items discussed in Environmental matters in Item 8 - Note 20. There are no pending CERCLA actions for any of the Company's properties, other than the Portland, Oregon, Harbor Superfund Site.
Governmental regulations establishing environmental protection standards are continuously evolving and, therefore, the character, scope, cost and availability of the measures that will permit
compliance with these laws or regulations cannot be accurately predicted. Disclosure regarding specific environmental matters applicable to each of the Company's businesses is set forth under each business description below.
This annual report on Form 10-K, the Company's quarterly reports on Form 10-Q, the Company's current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge through the Company's Web site as soon as reasonably practicable after the Company has electronically filed such reports with, or furnished such reports to, the SEC. The Company's Web site address is www.mdu.com. The information available on the Company's Web site is not part of this annual report on Form 10-K.
ELECTRIC
General Montana-Dakota provides electric service at retail, serving over 121,000 residential, commercial, industrial and municipal customers in 178 communities and adjacent rural areas as of December 31, 2008. The principal properties owned by Montana-Dakota for use in its electric operations include interests in eight electric generating facilities, as further described under System Supply, System Demand and Competition, and approximately 3,000 and 4,500 miles of transmission and distribution lines, respectively. Montana-Dakota has obtained and holds, or is in the process of renewing, valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises. As of December 31, 2008, Montana-Dakota's net electric plant investment approximated $438.3 million.
Substantially all of Montana-Dakota's electric properties are subject to the lien of the Mortgage and to the junior lien of the Indenture.
The percentage of Montana-Dakota's 2008 retail electric utility operating revenues by jurisdiction is as follows: North Dakota - 60 percent; Montana - 23 percent; Wyoming - 10 percent; and South Dakota - 7 percent. Retail electric rates, service, accounting and certain security issuances are subject to regulation by the NDPSC, MTPSC, SDPUC and WYPSC. The interstate transmission and wholesale electric power operations of Montana-Dakota also are subject to regulation by the FERC under provisions of the Federal Power Act, as are interconnections with other utilities and power generators, the issuance of securities, accounting and other matters. Montana-Dakota participates in the Midwest ISO wholesale energy and ancillary services market.
The Midwest ISO is a regional transmission organization responsible for operational control of the transmission systems of its members. The Midwest ISO provides security center operations, tariff administration and operates day-ahead and real-time energy markets and an ancillary services market. As a member of Midwest ISO, Montana-Dakota's generation is sold into the Midwest ISO energy market and its energy needs are purchased from that market.
System Supply, System Demand and Competition Through an interconnected electric system, Montana-Dakota serves markets in portions of western North Dakota, including Bismarck, Dickinson and Williston; eastern Montana, including Glendive and Miles City; and northern South Dakota, including Mobridge. The interconnected system consists of eight electric generating facilities, which have an aggregate nameplate rating attributable to Montana-Dakota's interest of 455,555 kW and a total summer net capability of 484,450 kW. Montana-Dakota's four principal generating stations are steam-turbine generating units using coal for fuel. The nameplate rating for Montana-Dakota's ownership interest in these four stations (including interests in the Big Stone
Station and the Coyote Station, aggregating 22.7 percent and 25.0 percent, respectively) is 327,758 kW. Three combustion turbine peaking stations and a wind-powered electric generating facility supply the balance of Montana-Dakota's interconnected system electric generating capability.
In September 2005, Montana-Dakota entered into a contract for seasonal capacity from a neighboring utility, starting at 85 MW in 2007, increasing to 105 MW in 2011, with an option for capacity in 2012. In April 2007, Montana-Dakota entered into a contract for seasonal capacity of 10 MW in May through October of each year continuing through 2010. Energy also will be purchased as needed from the Midwest ISO market. In 2008, Montana-Dakota purchased approximately 10 percent of its net kWh needs for its interconnected system through the Midwest ISO market.
The following table sets forth details applicable to the Company's electric generating stations:
* Reflects Montana-Dakota's ownership interest.
** Station use, to meet MAPP's accreditation requirements, exceeded generation.
Virtually all of the current fuel requirements of the Coyote, Heskett and Lewis & Clark stations are met with coal supplied by subsidiaries of Westmoreland. Contracts with Westmoreland for the Coyote, Heskett and Lewis & Clark stations expire in May 2016, April 2011 and December 2012, respectively. The Coyote coal supply agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station or 30,000 tons per week, whichever may be the greater quantity at contracted pricing. The maximum quantity of coal during the term of the agreement, and any extension, is 75 million tons. The Heskett and Lewis & Clark coal supply agreements provide for the purchase of coal necessary to supply the coal requirements of these stations at contracted pricing. Montana-Dakota estimates the Heskett and Lewis & Clark coal requirement to be in the range of 500,000 to 600,000 tons, and 250,000 to 350,000 tons per contract year, respectively.
A coal supply agreement, entered into in August 2007 with Kennecott, meets the majority of the Big Stone Station’s fuel requirements for the years 2009 and 2010 at contracted pricing. The Kennecott agreement provides for the purchase of 1.8 million and 1.0 million tons of coal in 2009 and 2010, respectively.
The average cost of coal purchased, including freight, at Montana-Dakota's electric generating stations (including the Big Stone and Coyote stations) was as follows:
The maximum electric peak demand experienced to date attributable to sales to retail customers on the interconnected system was 525,643 kW in July 2007. Montana-Dakota's latest forecast for its interconnected system indicates that its annual peak will continue to occur during the summer and the peak demand growth rate through 2014 will approximate one percent annually.
Montana-Dakota expects that it has adequate capacity available through existing baseload generating stations, wind-powered generation, turbine peaking stations and firm contracts to meet the peak demand requirements of its customers through 2012. Future capacity that is needed to replace contracts and meet system growth requirements is expected to be met by constructing new generation resources or acquiring additional capacity through power contracts. For additional information regarding potential power generation projects, see Item 7 - MD&A - Prospective Information - Electric.
Montana-Dakota has major interconnections with its neighboring utilities and considers these interconnections adequate for coordinated planning, emergency assistance, exchange of capacity and energy and power supply reliability.
Through the Sheridan System, Montana-Dakota serves Sheridan, Wyoming, and neighboring communities. The maximum peak demand experienced to date attributable to Montana-Dakota sales to retail customers on that system was approximately 60,600 kW in July 2007. In December 2004, Montana-Dakota entered into a power supply contract with Black Hills Power to purchase up to 74,000 kW of capacity annually from January 1, 2007 to December 31, 2016.
Montana-Dakota is subject to competition in varying degrees, in certain areas, from rural electric cooperatives, on-site generators, co-generators and municipally owned systems. In addition, competition in varying degrees exists between electricity and alternative forms of energy such as natural gas.
Regulatory Matters and Revenues Subject to Refund Fuel adjustment clauses contained in North Dakota and South Dakota jurisdictional electric rate schedules allow Montana-Dakota to reflect monthly increases or decreases in fuel and purchased power costs (excluding demand charges). In North Dakota, the Company is deferring electric fuel and purchased power costs (excluding demand charges) that are greater or less than amounts presently being recovered through its existing rate schedules. In Montana, a monthly Fuel and Purchased Power Tracking Adjustment mechanism allows Montana-Dakota to reflect 90 percent of the increases or decreases in fuel and purchased power costs (including demand charges) and Montana-Dakota is deferring 90 percent of costs that are greater or less than amounts presently being recovered through its existing rate schedules. In Wyoming, an annual Electric Power Supply Cost Adjustment mechanism allows Montana-Dakota to reflect increases or decreases in fuel and purchased power costs (including demand charges) related to power supply and Montana-Dakota is deferring costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments
within a period ranging from 14 to 25 months from the time such costs are paid. For additional information, see Item 8 - Note 6.
In August 2008, Montana-Dakota received an order from the NDPSC, approving its request for an advance determination of prudence of Montana-Dakota's ownership interest in Big Stone Station II. For additional information, see Item 8 - Note 19.
Environmental Matters Montana-Dakota's electric operations are subject to federal, state and local laws and regulations providing for air, water and solid waste pollution control; state facility-siting regulations; zoning and planning regulations of certain state and local authorities; federal health and safety regulations; and state hazard communication standards. Montana-Dakota believes it is in substantial compliance with these regulations.
Montana-Dakota's electric generating facilities have Title V Operating Permits, under the Clean Air Act, issued by the states in which it operates. Each of these permits has a five-year life. Near the expiration of these permits, renewal applications are submitted. Permits continue in force beyond the expiration date, provided the application for renewal is submitted by the required date, usually six months prior to expiration. Renewal is pending for the Big Stone Station Title V Operating Permit. The Coyote Station Title V Operating Permit was renewed in August 2008. An application for renewal was submitted for the Lewis & Clark Station Title V Operating Permit that expires in April 2009. Also, a Montana Air Quality Permit application was submitted as required for the Lewis & Clark Station to obtain a mercury permit emissions limit and approval of its proposed mercury emissions control strategy.
State water discharge permits issued under the requirements of the Clean Water Act are maintained for power production facilities on the Yellowstone and Missouri rivers. These permits also have five-year lives. Montana-Dakota renews these permits as necessary prior to expiration. Other permits held by these facilities may include an initial siting permit, which is typically a one-time, preconstruction permit issued by the state; state permits to dispose of combustion by-products; state authorizations to withdraw water for operations; and Army Corps permits to construct water intake structures. Montana-Dakota's Army Corps permits grant one-time permission to construct and do not require renewal. Other permit terms vary and the permits are renewed as necessary.
Montana-Dakota's electric operations are conditionally exempt small-quantity hazardous waste generators and subject only to minimum regulation under the RCRA. Montana-Dakota routinely handles PCBs from its electric operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required.
On June 10, 2008, the Sierra Club filed a complaint in the South Dakota Federal District Court against Montana-Dakota and the two other co-owners of the Big Stone Station. For more information regarding this complaint, see Item 8 - Note 20.
Montana-Dakota incurred $2.5 million of environmental expenditures in 2008. Expenditures are estimated to be $5.8 million, $6.0 million and $14.3 million in 2009, 2010 and 2011, respectively, to maintain environmental compliance as new emission controls are required. These estimates could be affected by potential new GHG emission legislation or regulations. Projects will include sulfur-dioxide and mercury control equipment installation at electric generating facilities. For matters involving Montana-Dakota and the ND Health Department, see Item 8 - Note 20.
NATURAL GAS DISTRIBUTION
General The Company's natural gas distribution operations consist of Montana-Dakota, Great Plains, Cascade and Intermountain which sell natural gas at retail, serving over 822,000 residential, commercial and industrial customers in 333 communities and adjacent rural areas across eight states as of December 31, 2008, and provide natural gas transportation services to certain customers on their systems. These services for the four public utility operations are provided through distribution systems aggregating approximately 17,000 miles. The natural gas distribution operations have obtained and hold, or are in the process of renewing, valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. These operations intend to protect their service areas and seek renewal of all expiring franchises. As of December 31, 2008, the natural gas distribution operations' net natural gas distribution plant investment approximated $757.7 million.
Substantially all of Montana-Dakota's natural gas distribution properties are subject to the lien of the Mortgage and to the junior lien of the Indenture.
The percentage of the natural gas distribution operations’ 2008 natural gas utility operating sales revenues by jurisdiction is as follows: Washington - 36 percent; North Dakota - 15 percent; Idaho - 13 percent; Oregon - 11 percent; Montana - 10 percent; South Dakota - 8 percent; Minnesota - 5 percent; and Wyoming - 2 percent. The above percentages reflect operating sales revenues of Intermountain since October 1, 2008, the date of acquisition. The natural gas distribution operations are subject to regulation by the IPUC, MNPUC, MTPSC, NDPSC, OPUC, SDPUC, WUTC and WYPSC regarding retail rates, service, accounting and certain security issuances.
System Supply, System Demand and Competition The natural gas distribution operations serve retail natural gas markets, consisting principally of residential and firm commercial space and water heating users, in portions of Idaho, including Boise, Nampa, Twin Falls, Pocatello and Idaho Falls; western Minnesota, including Fergus Falls, Marshall and Crookston; eastern Montana, including Billings, Glendive and Miles City; North Dakota, including Bismarck, Dickinson, Wahpeton, Williston, Minot and Jamestown; central and eastern Oregon, including Bend and Pendleton; western and north-central South Dakota, including Rapid City, Pierre, Spearfish and Mobridge; western, southeastern and south-central Washington, including Bellingham, Bremerton, Longview, Moses Lake, Mount Vernon, Tri-Cities, Walla Walla and Yakima; and northern Wyoming, including Sheridan. These markets are highly seasonal and sales volumes depend largely on the weather, the effects of which are mitigated in certain jurisdictions by a weather normalization mechanism discussed in Regulatory Matters.
Competition in varying degrees exists between natural gas and other fuels and forms of energy. The natural gas distribution operations have established various natural gas transportation service rates for their distribution businesses to retain interruptible commercial and industrial loads. Certain of these services include transportation under flexible rate schedules whereby interruptible customers can avail themselves of the advantages of open access transportation on regional transmission pipelines, including the systems of Williston Basin, Northern Natural Gas Company, Viking Gas Transmission Company, Northwest Pipeline GP and Gas Transmission Northwest Corporation. These services have enhanced the natural gas distribution operations' competitive posture with alternative fuels, although certain customers have bypassed the distribution systems by directly accessing transmission pipelines located within close proximity. These bypasses did not have a material effect on results of operations.
The natural gas distribution operations obtain their system requirements directly from producers, processors and marketers. Such natural gas is supplied by a portfolio of contracts specifying market-based pricing and is transported under transportation agreements by Williston Basin, South Dakota Intrastate Pipeline Company, Northern Border Pipeline Company, Viking Gas Transmission Company, Northern Natural Gas Company, Source Gas, TransCanada Alberta System, TransCanada Foothills System, Northwestern Energy, Northwest Pipeline GP, Gas Transmission Northwest Corporation and Spectra Energy Gas Transmission. Montana-Dakota also has contracted with Williston Basin, Great Plains with Northern Natural Gas Company, and both Cascade and Intermountain with Northwest Pipeline GP, to provide firm storage services that enable all four operations to meet winter peak requirements. Demand for natural gas, which is a widely traded commodity, has historically been sensitive to seasonal heating and industrial load requirements as well as changes in market price. The natural gas distribution operations believe that, based on regional supplies of natural gas and the pipeline transmission network currently available through their suppliers and pipeline service providers, supplies are adequate to meet their system natural gas requirements for the next five years.
Regulatory Matters The natural gas distribution operations' retail natural gas rate schedules contain clauses permitting adjustments in rates based upon changes in natural gas commodity, transportation and storage costs. Current tariffs allow for recovery or refunds of under or over recovered gas costs within a period ranging from 12 to 28 months.
Montana-Dakota's North Dakota and South Dakota natural gas tariffs contain a weather normalization mechanism applicable to firm customers that adjusts the distribution delivery charge revenues to reflect weather fluctuations during the November 1 through May 1 billing periods.
Cascade has received approval for decoupling its margins from weather and conservation in Oregon, and has also received approval of a decoupling mechanism in Washington which allows it to recover margin differences resulting from customer conservation. Cascade also has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the OPUC.
Environmental Matters The natural gas distribution operations are subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. The natural gas distribution operations believe they are in substantial compliance with those regulations.
Natural gas distribution operations are conditionally exempt small-quantity hazardous waste generators and subject only to minimum regulation under the RCRA. The natural gas distribution operations routinely handle PCBs from their natural gas operations in accordance with federal requirements. PCB storage areas are registered with the EPA as required.
The natural gas distribution operations did not incur any material environmental expenditures in 2008 and, except as to what may be ultimately determined with regard to the issues described below, do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations in relation to the natural gas distribution operations through 2011.
Montana-Dakota has had an economic interest in five historic manufactured gas plants within its service territory, none of which are currently being actively investigated, and for which any remediation expenses are not expected to be material. Cascade has had an economic interest in nine former manufactured gas plants within its service territory. Cascade has been involved with other PRPs in the investigation of a manufactured gas plant site in Oregon, with remediation of
this site pending additional investigation. See Item 8 - Note 20 for a further discussion of this site and for two additional sites for which Cascade has received claim notice. To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers.
CONSTRUCTION SERVICES
General MDU Construction Services specializes in constructing and maintaining electric and communication lines, gas pipelines, fire protection systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment. These services are provided to utilities and large manufacturing, commercial, industrial, institutional and government customers.
In 2008, the Company acquired a construction service business in Nevada. This acquisition was not material to the Company.
Construction and maintenance crews are active year round. However, activity in certain locations may be seasonal in nature due to the effects of weather.
MDU Construction Services operates a fleet of owned and leased trucks and trailers, support vehicles and specialty construction equipment, such as backhoes, excavators, trenchers, generators, boring machines and cranes. In addition, as of December 31, 2008, MDU Construction Services owned or leased facilities in 16 states. This space is used for offices, equipment yards, warehousing, storage and vehicle shops. At December 31, 2008, MDU Construction Services' net plant investment was approximately $50.3 million.
MDU Construction Services' backlog is comprised of the uncompleted portion of services to be performed under job-specific contracts. The backlog at December 31, 2008, was approximately $604 million compared to $827 million at December 31, 2007. MDU Construction Services expects to complete a significant amount of this backlog during the year ending December 31, 2009. Due to the nature of its contractual arrangements, in many instances MDU Construction Services' customers are not committed to the specific volumes of services to be purchased under a contract, but rather MDU Construction Services is committed to perform these services if and to the extent requested by the customer. Therefore, there can be no assurance as to the customer's requirements during a particular period or that such estimates at any point in time are predictive of future revenues.
This industry is experiencing a shortage of skilled laborers in certain areas. MDU Construction Services works with the National Electrical Contractors Association, the IBEW and other trade associations on hiring and recruiting a qualified workforce.
Competition MDU Construction Services operates in a highly competitive business environment. Most of MDU Construction Services' work is obtained on the basis of competitive bids or by negotiation of either cost-plus or fixed-price contracts. The workforce and equipment are highly mobile, providing greater flexibility in the size and location of MDU Construction Services' market area. Competition is based primarily on price and reputation for quality, safety and reliability. The size and location of the services provided, as well as the state of the economy, will be factors in the number of competitors that MDU Construction Services will encounter on any particular project. MDU Construction Services believes that the diversification of the services it
provides, the markets it serves throughout the United States and the management of its workforce will enable it to effectively operate in this competitive environment.
Utilities and independent contractors represent the largest customer base for this segment. Accordingly, utility and subcontract work accounts for a significant portion of the work performed by MDU Construction Services and the amount of construction contracts is dependent to a certain extent on the level and timing of maintenance and construction programs undertaken by customers. MDU Construction Services relies on repeat customers and strives to maintain successful long-term relationships with these customers.
Environmental Matters MDU Construction Services' operations are subject to regulation customary for the industry, including federal, state and local environmental compliance. MDU Construction Services believes it is in substantial compliance with these regulations.
The nature of MDU Construction Services' operations is such that few, if any, environmental permits are required. Operational convenience supports the use of petroleum storage tanks in several locations, which are permitted under state programs authorized by the EPA. MDU Construction Services has no ongoing remediation related to releases from petroleum storage tanks. MDU Construction Services' operations are conditionally exempt small-quantity waste generators, subject to minimal regulation under the RCRA. Federal permits for specific construction and maintenance jobs that may require these permits are typically obtained by the hiring entity, and not by MDU Construction Services.
MDU Construction Services did not incur any material environmental expenditures in 2008 and does not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2011.
PIPELINE AND ENERGY SERVICES
General Williston Basin, the regulated business of WBI Holdings, owns and operates over 3,700 miles of transmission, gathering and storage lines and owns or leases and operates 32 compressor stations in the states of Montana, North Dakota, South Dakota and Wyoming. Three underground storage fields in Montana and Wyoming provide storage services to local distribution companies, producers, natural gas marketers and others, and serve to enhance system deliverability. Williston Basin's system is strategically located near five natural gas producing basins, making natural gas supplies available to Williston Basin's transportation and storage customers. The system has 11 interconnecting points with other pipeline facilities allowing for the receipt and/or delivery of natural gas to and from other regions of the country and from Canada. At December 31, 2008, Williston Basin's net plant investment was approximately $263.5 million. Under the Natural Gas Act, as amended, Williston Basin is subject to the jurisdiction of the FERC regarding certificate, rate, service and accounting matters.
Bitter Creek, the nonregulated pipeline business, owns and operates gathering facilities in Colorado, Kansas, Montana and Wyoming. Bitter Creek also owns a one-sixth interest in the assets of various offshore gathering pipelines, an associated onshore pipeline and related processing facilities in Texas. In total, these facilities include over 1,900 miles of field gathering lines and 90 owned or leased compression stations, some of which interconnect with Williston Basin's system. In addition, Bitter Creek provides a variety of energy-related services such as water hauling, contract compression operations, measurement services and energy efficiency product sales and installation services to large end-users.
WBI Holdings, through its energy services business, provides natural gas purchase and sales services to local distribution companies, producers, other marketers and a limited number of large end-users, primarily using natural gas produced by the Company's natural gas and oil production segment. Certain of the services are provided based on contracts that call for a determinable quantity of natural gas. WBI Holdings currently estimates that it can adequately meet the requirements of these contracts. WBI Holdings transacts a substantial majority of its pipeline and energy services business in the northern Great Plains and Rocky Mountain regions of the United States.
System Demand and Competition Williston Basin competes with several pipelines for its customers' transportation, storage and gathering business and at times may discount rates in an effort to retain market share. However, the strategic location of Williston Basin's system near five natural gas producing basins and the availability of underground storage and gathering services provided by Williston Basin and affiliates along with interconnections with other pipelines serve to enhance Williston Basin's competitive position.
Although certain of Williston Basin's firm customers, including its largest firm customer Montana-Dakota, serve relatively secure residential and commercial end-users, they generally all have some price-sensitive end-users that could switch to alternate fuels.
Williston Basin transports substantially all of Montana-Dakota's natural gas, primarily utilizing firm transportation agreements, which for the year ended December 31, 2008, represented 54 percent of Williston Basin's subscribed firm transportation contract demand. Montana-Dakota has a firm transportation agreement with Williston Basin for a term of five years expiring in June 2012. In addition, Montana-Dakota has a contract with Williston Basin to provide firm storage services to facilitate meeting Montana-Dakota's winter peak requirements for a term of 20 years expiring in July 2015.
Bitter Creek competes with several pipelines for existing customers and the expansion of its systems to gather natural gas in new areas. Bitter Creek's strong position in the fields in which it operates, its focus on customer service and the variety of services it offers, along with its interconnection with various other pipelines, serve to enhance its competitive position.
System Supply Williston Basin's underground natural gas storage facilities have a certificated storage capacity of approximately 353 Bcf, including 193 Bcf of working gas capacity, 85 Bcf of cushion gas and 75 Bcf of native gas. The native gas includes an estimated 29 Bcf of recoverable gas. Williston Basin's storage facilities enable its customers to purchase natural gas at more uniform daily volumes throughout the year, which facilitates meeting winter peak requirements. For information regarding natural gas storage legal proceedings, see Item 1A - Risk Factors - Other Risks and Item 8 - Note 20.
Natural gas supplies emanate from traditional and nontraditional natural gas production activities in the region and from off-system supply sources. While certain traditional regional supply sources are in various stages of decline, incremental supply from nontraditional sources have been developed which have helped support Williston Basin's supply needs. This includes new natural gas supply associated with the continued development of the Bakken area in Montana and North Dakota. The Powder River Basin, including the Company's CBNG assets, also provides a nontraditional natural gas supply to the Williston Basin system. For additional information regarding CBNG legal proceedings, see Item 1A - Risk Factors - Environmental and Regulatory Risks and Item 8 - Note 20. In addition, off-system supply sources are available through the
Company's interconnections with other pipeline systems. Williston Basin expects to facilitate the movement of these supplies by making available its transportation and storage services. Williston Basin will continue to look for opportunities to increase transportation, gathering and storage services through system expansion and/or other pipeline interconnections or enhancements that could provide substantial future benefits.
Regulatory Matters and Revenues Subject to Refund In December 1999, Williston Basin filed a general natural gas rate change application with the FERC. For additional information, see Item 8 - Note 19.
Environmental Matters WBI Holdings' pipeline and energy services operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. WBI Holdings believes it is in substantial compliance with those regulations.
Ongoing operations are subject to the Clean Air Act and the Clean Water Act. Administration of many provisions of these laws has been delegated to the states where Williston Basin and Bitter Creek operate, and permit terms vary. Some permits require annual renewal, some have terms ranging from one to five years and others have no expiration date. Permits are renewed as necessary.
Detailed environmental assessments are included in the FERC's permitting processes for both the construction and abandonment of Williston Basin's natural gas transmission pipelines, compressor stations and storage facilities.
WBI Holdings' pipeline and energy services operations did not incur any material environmental expenditures in 2008 and do not expect to incur any material capital expenditures related to environmental compliance with current laws and regulations through 2011.
NATURAL GAS AND OIL PRODUCTION
General Fidelity is involved in the acquisition, exploration, development and production of natural gas and oil resources. Fidelity's activities include the acquisition of producing properties and leaseholds with potential development opportunities, exploratory drilling and the operation and development of natural gas and oil production properties. Fidelity continues to seek additional reserve and production growth opportunities through these activities. Future growth is dependent upon its success in these endeavors. Fidelity shares revenues and expenses from the development of specified properties in proportion to its ownership interests.
Fidelity's business is focused primarily in three core regions: Rocky Mountain, Mid-Continent/Gulf States and Offshore Gulf of Mexico.
Rocky Mountain
Fidelity's properties in this region are primarily located in the states of Colorado, Montana, North Dakota, Utah and Wyoming. Fidelity owns in fee or holds natural gas and oil leases for the properties it operates that are in the Bonny Field located in eastern Colorado, the Baker Field in southeastern Montana and southwestern North Dakota, the Bowdoin area located in north-central Montana, the Powder River Basin of Montana and Wyoming, the Bakken area in North Dakota, the Paradox Basin of Utah, and the Big Horn Basin of Wyoming. Fidelity also owns nonoperated natural gas and oil interests and undeveloped acreage positions in this region.
Mid-Continent/Gulf States
This region includes properties in Alabama, Louisiana, New Mexico, Oklahoma and Texas. Fidelity owns in fee or holds natural gas and oil leases for the properties it operates that are in the Tabasco and Texan Gardens fields of Texas. In 2008, Fidelity acquired and became the operator of natural gas properties in Rusk County in eastern Texas. In addition, Fidelity owns several nonoperated interests and undeveloped acreage positions in this region.
Offshore Gulf of Mexico
Fidelity has nonoperated interests throughout the Offshore Gulf of Mexico. These interests are primarily located in the shallow waters off the coasts of Texas and Louisiana.
Operating Information Annual net production by region for 2008 was as follows:
Well and Acreage Information Gross and net productive well counts and gross and net developed and undeveloped acreage related to Fidelity's interests at December 31, 2008, were as follows:
Exploratory and Development Wells The following table reflects activities relating to Fidelity's natural gas and oil wells drilled and/or tested during 2008, 2007 and 2006:
At December 31, 2008, there were 117 gross (85 net) wells in the process of drilling or under evaluation, 105 of which were development wells and 12 of which were exploratory wells. These wells are not included in the previous table. Fidelity expects to complete the drilling and testing of the majority of these wells within the next 12 months.
The information in the table above should not be considered indicative of future performance nor should it be assumed that there is necessarily any correlation between the number of productive
wells drilled and quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.
Competition The natural gas and oil industry is highly competitive. Fidelity competes with a substantial number of major and independent natural gas and oil companies in acquiring producing properties and new leases for future exploration and development, and in securing the equipment, services and expertise necessary to explore, develop and operate its properties.
Environmental Matters Fidelity's natural gas and oil production operations are generally subject to federal, state and local environmental, facility-siting, zoning and planning laws and regulations. Fidelity believes it is in substantial compliance with these regulations.
The ongoing operations of Fidelity are subject to the Clean Water Act, the Clean Air Act, and other federal and state environmental regulations. Administration of many provisions of the federal laws has been delegated to the states where Fidelity operates, and permit terms vary. Some permits have terms ranging from one to five years and others have no expiration date.
Detailed environmental assessments and/or environmental impact statements under federal and state laws are required as part of the permitting process incidental to the commencement of drilling and production operations as well as in the closure, abandonment and reclamation of facilities.
In connection with production operations, Fidelity has incurred certain capital expenditures related to water handling. For 2008, capital expenditures for water handling in compliance with current laws and regulations were approximately $2.8 million and are estimated to be approximately $3.3 million, $12.8 million and $7.3 million in 2009, 2010 and 2011, respectively. These water handling costs are primarily related to the CBNG properties. For more information regarding CBNG legal proceedings, see Item 1A - Risk Factors and Item 8 - Note 20.
Reserve Information Estimates of reserves are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing available geological, geophysical, engineering and economic data. Other factors used in the reserve estimates are current natural gas and oil prices, current estimates of well operating and future development costs, taxes, timing of operations, and the interest owned by the Company in the well. The reserve estimates are prepared by internal engineers and are reviewed by management. These estimates are refined as new information becomes available.
Fidelity's recoverable proved reserves by region at December 31, 2008, are as follows:
* Pre-tax PV-10 value is a non-GAAP financial measure that is derived from the most directly comparable GAAP financial measure which is the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows disclosed in Item 8 - Supplementary Financial Information, is presented after deducting discounted future income taxes in accordance with SFAS No. 69, whereas the PV-10 value is presented before income taxes. Pre-tax PV-10 value is commonly used by the Company to evaluate properties that are acquired and sold and to assess the potential return on investment in the Company's natural gas and oil properties. The Company believes pre-tax PV-10 value is a useful supplemental disclosure to the standardized measure as the Company believes readers may utilize this value as a basis for comparison of the relative size and value of the Company’s reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. However, pre-tax PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Neither the Company's pre-tax PV-10 value nor the standardized measure of discounted future net cash flows purports to represent the fair value of the Company's natural gas and oil properties.
For additional information related to natural gas and oil interests, see Item 8 - Note 1 and Supplementary Financial Information.
CONSTRUCTION MATERIALS AND CONTRACTING
General Knife River operates construction materials and contracting businesses headquartered in Alaska, California, Hawaii, Idaho, Iowa, Minnesota, Montana, North Dakota, Oregon, Texas, Washington and Wyoming. These operations mine, process and sell construction aggregates (crushed stone, sand and gravel); produce and sell asphalt mix and supply liquid asphalt for various commercial and roadway applications; and supply ready-mixed concrete for use in most types of construction, including roads, freeways and bridges, as well as homes, schools, shopping centers, office buildings and industrial parks. Although not common to all locations, other products include the sale of cement, various finished concrete products and other building materials and related contracting services.
During 2008, the Company acquired construction materials and contracting businesses with operations in Alaska, California, Idaho and Texas. None of these acquisitions was material to the Company.
Knife River continues to investigate the acquisition of other construction materials properties, particularly those relating to construction aggregates and related products such as ready-mixed concrete, asphalt and related construction services.
The construction materials business had approximately $453 million in backlog at December 31, 2008, compared to $462 million at December 31, 2007. The Company anticipates that a significant amount of the current backlog will be completed during the year ending December 31, 2009.
Competition Knife River's construction materials products are marketed under highly competitive conditions. Price is the principal competitive force to which these products are subject, with service, quality, delivery time and proximity to the customer also being significant factors. The number and size of competitors varies in each of Knife River's principal market areas and product lines.
The demand for construction materials products is significantly influenced by the cyclical nature of the construction industry in general. In addition, construction materials activity in certain locations may be seasonal in nature due to the effects of weather. The key economic factors affecting product demand are changes in the level of local, state and federal governmental spending, general economic conditions within the market area that influence both the commercial and private sectors, and prevailing interest rates.
Knife River is not dependent on any single customer or group of customers for sales of its products and services, the loss of which would have a material adverse effect on its construction materials businesses.
Reserve Information Reserve estimates are calculated based on the best available data. These data are collected from drill holes and other subsurface investigations, as well as investigations of surface features such as mine highwalls and other exposures of the aggregate reserves. Mine plans, production history and geologic data also are utilized to estimate reserve quantities. Most acquisitions are made of mature businesses with established reserves, as distinguished from exploratory-type properties.
Estimates are based on analyses of the data described above by experienced internal mining engineers, operating personnel and geologists. Property setbacks and other regulatory restrictions and limitations are identified to determine the total area available for mining. Data described above are used to calculate the thickness of aggregate materials to be recovered. Topography associated with alluvial sand and gravel deposits is typically flat and volumes of these materials are calculated by applying the thickness of the resource over the areas available for mining. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 1.5 tons per cubic yard in the ground is used for sand and gravel deposits.
Topography associated with the hard rock reserves is typically much more diverse. Therefore, using available data, a final topography map is created and computer software is utilized to compute the volumes between the existing and final topographies. Volumes are then converted to tons by using an appropriate conversion factor. Typically, 2 tons per cubic yard in the ground is used for hard rock quarries.
Estimated reserves are probable reserves as defined in Securities Act Industry Guide 7. Remaining reserves are based on estimates of volumes that can be economically extracted and sold to meet current market and product applications. The reserve estimates include only salable tonnage and
thus exclude waste materials that are generated in the crushing and processing phases of the operation. Approximately 1.0 billion tons of the 1.1 billion tons of aggregate reserves are permitted reserves. The remaining reserves are on properties that are expected to be permitted for mining under current regulatory requirements. The data used to calculate the remaining reserves may require revisions in the future to account for changes in customer requirements and unknown geological occurrences. The years remaining were calculated by dividing remaining reserves by the three-year average sales from 2006 through 2008. Actual useful lives of these reserves will be subject to, among other things, fluctuations in customer demand, customer specifications, geological conditions and changes in mining plans.
The following table sets forth details applicable to the Company's aggregate reserves under ownership or lease as of December 31, 2008, and sales for the years ended December 31, 2008, 2007 and 2006:
The 1.1 billion tons of estimated aggregate reserves at December 31, 2008, is comprised of 470 million tons that are owned and 675 million tons that are leased. Approximately 51 percent of the tons under lease have lease expiration dates of 20 years or more. The weighted average years remaining on all leases containing estimated probable aggregate reserves is approximately 21 years, including options for renewal that are at Knife River's discretion. Based on a three-year average of sales from 2006 through 2008 of leased reserves, the average time necessary to produce remaining aggregate reserves from such leases is approximately 46 years. Some sites have leases that expire prior to the exhaustion of the estimated reserves. The estimated reserve life assumes, based on Knife River's experience, that leases will be renewed to allow sufficient time to fully recover these reserves.
The following table summarizes Knife River's aggregate reserves at December 31, 2008, 2007 and 2006, and reconciles the changes between these dates:
Environmental Matters Knife River's construction materials and contracting operations are subject to regulation customary for such operations, including federal, state and local environmental compliance and reclamation regulations. Except as to what may be ultimately determined with regard to the Portland, Oregon, Harbor Superfund Site issue described later, Knife River believes it is in substantial compliance with these regulations.
Knife River's asphalt and ready-mixed concrete manufacturing plants and aggregate processing plants are subject to Clean Air Act and Clean Water Act requirements for controlling air emissions and water discharges. Some mining and construction activities also are subject to these laws. In most of the states where Knife River operates, these regulatory programs have been delegated to state and local regulatory authorities. Knife River's facilities also are subject to RCRA as it applies to the management of hazardous wastes and underground storage tank systems. These programs also have generally been delegated to the state and local authorities in the states where Knife River operates. Knife River's facilities must comply with requirements for managing wastes and underground storage tank systems.
Some Knife River activities are directly regulated by federal agencies. For example, gravel bar skimming and deep water dredging operations are subject to provisions of the Clean Water Act that are administered by the Army Corps. Knife River operates gravel bar skimming operations and deep water dredging operations in Oregon, all of which are subject to joint permits with the Army Corps and Oregon Department of State Lands. The expiration dates of these permits vary, with five years generally being the longest term. None of these in-water mining operations are included in Knife River's aggregate reserve numbers.
Knife River's operations also are occasionally subject to the ESA. For example, land use regulations often require environmental studies, including wildlife studies, before a permit may be granted for a new or expanded mining facility or an asphalt or concrete plant. If endangered species or their habitats are identified, ESA requirements for protection, mitigation or avoidance apply. Endangered species protection requirements are usually included as part of land use permit conditions. Typical conditions include avoidance, setbacks, restrictions on operations during certain times of the breeding or rearing season, and construction or purchase of mitigation habitat. Knife River's operations also are subject to state and federal cultural resources protection laws when new areas are disturbed for mining operations or processing plants. Land use permit applications generally require that areas proposed for mining or other surface disturbances be surveyed for cultural resources. If any are identified, they must be protected or managed in accordance with regulatory agency requirements.
The most comprehensive environmental permit requirements are usually associated with new mining operations, although requirements vary widely from state to state and even within states. In some areas, land use regulations and associated permitting requirements are minimal. However, some states and local jurisdictions have very demanding requirements for permitting new mines. Environmental impact reports are sometimes required before a mining permit application can even be considered for approval. These reports can take up to several years to complete. The report can include projected impacts of the proposed project on air and water quality, wildlife, noise levels, traffic, scenic vistas and other environmental factors. The reports generally include suggested actions to mitigate the projected adverse impacts.
Provisions for public hearings and public comments are usually included in land use permit application review procedures in the counties where Knife River operates. After taking into account environmental, mine plan and reclamation information provided by the permittee as well as comments from the public and other regulatory agencies, the local authority approves or denies the permit application. Denial is rare but land use permits often include conditions that must be addressed by the permittee. Conditions may include property line setbacks, reclamation requirements, environmental monitoring and reporting, operating hour restrictions, financial guarantees for reclamation, and other requirements intended to protect the environment or address concerns submitted by the public or other regulatory agencies.
Knife River has been successful in obtaining mining and other land use permit approvals so that sufficient permitted reserves are available to support its operations. For mining operations, this often requires considerable advanced planning to ensure sufficient time is available to complete the permitting process before the newly permitted aggregate reserve is needed to support Knife River's operations.
Knife River's Gascoyne surface coal mine last produced coal in 1995 but continues to be subject to reclamation requirements of the SMCRA, as well as the North Dakota Surface Mining Act. Portions of the Gascoyne Mine remain under reclamation bond until the 10-year revegetation liability period has expired. A portion of the original permit has been released from bond and additional areas are currently in the process of having the bond released. Knife River's intention is to request bond release as soon as it is deemed possible with all final bond release applications being filed by 2013.
Knife River did not incur any material environmental expenditures in 2008 and, except as to what may be ultimately determined with regard to the issue described below, Knife River does not expect to incur any material expenditures related to environmental compliance with current laws and regulations through 2011.
In December 2000, MBI was named by the EPA as a PRP in connection with the cleanup of a commercial property site, acquired by MBI in 1999, and part of the Portland, Oregon, Harbor Superfund Site. For additional information, see Item 8 - Note 20.
ITEM 1A. RISK FACTORS
The Company's business and financial results are subject to a number of risks and uncertainties, including those set forth below and in other documents that it files with the SEC. The factors and the other matters discussed herein are important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in the forward-looking statements included elsewhere in this document.
Economic Risks
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.
These factors include: fluctuations in natural gas and oil prices; fluctuations in commodity price basis differentials; availability of economic supplies of natural gas; drilling successes in natural gas and oil operations; the timely receipt of necessary permits and approvals; the ability to contract for or to secure necessary drilling rig and service contracts and to retain employees to drill for and develop reserves; the ability to acquire natural gas and oil properties; and other risks incidental to the operations of natural gas and oil wells. Recent volatility in natural gas and oil prices has negatively affected the results of operations and cash flows of the Company's natural gas and oil production and pipeline and energy services businesses.
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.
The construction, startup and operation of power generation facilities involve many risks, including: delays; breakdown or failure of equipment; competition; inability to obtain required governmental permits and approvals; inability to negotiate acceptable acquisition, construction, fuel supply, off-take, transmission or other material agreements; changes in market price for power; cost increases; as well as the risk of performance below expected levels of output or efficiency. Such unanticipated events could negatively impact the Company's business, its results of operations and cash flows.
The Company is analyzing potential projects for accommodating load growth and replacing purchased power and capacity with company-owned generation which would add capacity and rate base. A potential project is the planned participation in Big Stone Station II. Should regulatory approvals and permits not be received on a timely basis, or adverse permit conditions be attached, the project could be at risk and the Company would need to pursue other generation sources.
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 and, as a result, may have a negative impact on the Company's future revenues and cash flows.
The global demand for natural resources, interest rates, governmental budget constraints and the ongoing threat of terrorism can create volatility in the financial markets. The current economic slowdown has negatively affected the level of public and private expenditures on projects and the timing of these projects which, in turn, has negatively affected the demand for certain of the Company's products and services. Continued economic volatility could adversely impact the Company's results of operations and cash flows. Changing market conditions could negatively affect the market value of assets held in the Company’s pension and other postretirement benefit plans and may increase the amount and accelerate the timing of required funding contributions.
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.
The Company relies on access to both short-term borrowings, including the issuance of commercial paper, and long-term capital markets as sources of liquidity for capital requirements not satisfied by its cash flow from operations. If the Company is not able to access capital at competitive rates, the ability to implement its business plans may be adversely affected. Market disruptions, such as those currently being experienced in the United States and abroad, or a downgrade of the Company's credit ratings may increase the cost of borrowing or adversely affect its ability to access one or more financial markets. Such disruptions could include:
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A severe prolonged economic downturn
·
The bankruptcy of unrelated industry leaders in the same line of business
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Further deterioration in capital market conditions
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Turmoil in the financial services industry
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Volatility in commodity prices
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Terrorist attacks
Economic turmoil, market disruptions and volatility in the securities trading markets, as well as other factors including changes in the Company's financial condition, results of operations and prospects, and sales of substantial amounts of the Company's common stock, or the perception that such sales could occur, may adversely affect the market price of the Company's common stock.
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 process of estimating natural gas and oil reserves is complex. Reserve estimates are based on assumptions relating to natural gas and oil pricing, drilling and operating expenses, capital expenditures, taxes, timing of operations, and the percentage of interest owned by the Company in the well. The reserve estimates are prepared for each of our properties by internal engineers assigned to an asset team by geographic area. The internal engineers analyze available geological, geophysical, engineering and economic data for each geographic area. The internal engineers make various assumptions regarding this data. The extent, quality and reliability of this data can vary. Although we have prepared our reserve estimates in accordance with guidelines established by the industry and the SEC, significant changes to the reserve estimates may occur based on actual results of production, drilling, costs and pricing.
In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be significantly different. Sustained downward movements in natural gas and oil prices could result in additional future write-downs of the Company's natural gas and oil properties.
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive environmental laws and regulations that may increase costs of operations, impact or limit business plans, or expose the Company to environmental liabilities.
The Company is subject to extensive environmental laws and regulations affecting many aspects of its present and future operations including air quality, water quality, waste management and other environmental considerations. These laws and regulations can result in increased capital, operating and other costs, and delays as a result of ongoing litigation and administrative proceedings and compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions and CBNG development. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Public officials and entities, as well as private individuals and organizations, may seek injunctive relief or other remedies to enforce applicable environmental laws and regulations. The Company cannot predict the outcome (financial or operational) of any related litigation or administrative proceedings that may arise.
Existing environmental regulations may be revised and new regulations seeking to protect the environment may be adopted or become applicable to the Company. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on the Company's results of operations and cash flows.
The Company's electric generation operations could be adversely impacted by global climate change initiatives to reduce GHG emissions.
Concern that GHG emissions are contributing to global climate change has led to federal and state legislative and regulatory proposals to reduce or mitigate the effects of GHG emissions. The primary GHG emitted from the Company's operations is carbon dioxide from combustion of fossil fuels at Montana-Dakota's electric generating facilities, particularly its coal-fired electric generating facilities. More than 70 percent of the electricity generated by Montana-Dakota is from coal-fired plants and Montana-Dakota plans to participate in the construction and operation of two new coal-fired plants. Montana-Dakota also owns approximately 100 MW of natural gas- and oil-fired peaking plants. Implementation of legislation or regulations to reduce GHG emissions could affect Montana-Dakota's electric utility operations by requiring the expansion of energy conservation efforts and/or the increased development of renewable energy sources, as well as instituting other mandates that could significantly increase the capital expenditures and operating costs at its fossil fuel-fired generating facilities. Due to the uncertainty of technologies available to control GHG emissions and the unknown nature of compliance obligations with potential GHG emission legislation or regulations, the Company cannot determine the financial impact on its operations. If Montana-Dakota does not receive timely and full recovery of the costs of complying with GHG emission legislation and regulations from its customers, then such requirements could have an adverse impact on the results of its operations.
One of the Company's subsidiaries is subject to ongoing litigation and administrative proceedings in connection with its CBNG development activities. These proceedings have caused delays in CBNG drilling activity, and the ultimate outcome of the actions could have a material negative effect on existing CBNG operations and/or the future development of its CBNG properties.
Fidelity has been named as a defendant in, and/or certain of its operations are or have been the subject of, more than a dozen lawsuits filed in connection with its CBNG development in the Powder River Basin in Montana and Wyoming. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could have a material negative effect on Fidelity's existing CBNG operations and/or the future development of its CBNG properties.
The BER in March 2006 issued a decision in a rulemaking proceeding, initiated by the NPRC, that amends the non-degradation policy applicable to water discharged in connection with CBNG operations. The amended policy includes additional limitations on factors deemed harmful, thereby restricting water discharges even further than under previous standards. Due in part to this amended policy, in May 2006, the Northern Cheyenne Tribe commenced litigation in Montana state court challenging two five-year water discharge permits that the Montana DEQ granted to Fidelity in February 2006 and which are critical to Fidelity's ability to manage water produced under present and future CBNG operations. Although the Montana state court decided the case in favor of Fidelity and the Montana DEQ in December 2008, the case is not final and may be appealed until March 23, 2009. If these permits are set aside, Fidelity's CBNG operations in Montana could be significantly and adversely affected.
The Company is subject to extensive 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.
The Company is subject to regulation by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return, financing, industry rate structures, and recovery of purchased power and purchased gas costs. These governmental regulations significantly influence the Company’s operating environment and may affect its ability to recover costs from its customers. The Company is unable to predict the impact on operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on the Company’s results of operations and cash flows. Approval from a number of federal and state regulatory agencies would need to be obtained by any potential acquirer of the Company. The approval process could be lengthy and the outcome uncertain.
Risks Relating to Foreign Operations
The value of the Company's investments in foreign operations may diminish due to political, regulatory and economic conditions and changes in currency exchange rates in countries where the Company does business.
The Company is subject to political, regulatory and economic conditions and changes in currency exchange rates in foreign countries where the Company does business. Significant changes in the political, regulatory or economic environment in these countries could negatively affect the value of the Company's investments located in these countries. Also, since the Company is unable to predict the fluctuations in the foreign currency exchange rates, these fluctuations may have an adverse impact on the Company's results of operations and cash flows.
Other Risks
One of the Company's subsidiaries is engaged in litigation with a nonaffiliated natural gas producer that has been conducting drilling and production operations that the subsidiary believes is causing diversion and loss of quantities of storage gas from one of its storage
reservoirs. If the subsidiary is not able to obtain relief through the courts or the regulatory process, its storage operations could be materially and adversely affected.
Based on relevant information, including reservoir and well pressure data, Williston Basin believes that EBSR pressures have decreased and that the storage reservoir has lost gas and continues to lose gas as a result of the drilling and production activities of Anadarko and its wholly owned subsidiary, Howell. Williston Basin filed suit in Montana Federal District Court seeking to recover unspecified damages from Anadarko and Howell, and to enjoin Anadarko and Howell's present and future production operations in and near the EBSR. This suit was dismissed by the Montana Federal District Court. The dismissal was affirmed by the Ninth Circuit. In related litigation, Howell filed suit in Wyoming State District Court against Williston Basin asserting that it is entitled to produce any gas that might escape from Williston Basin's storage reservoir. Williston Basin has answered Howell's complaint and has asserted counterclaims. If Williston Basin is unable to obtain timely relief through the courts or regulatory process, its present and future gas storage operations, including its ability to meet its contractual storage and transportation obligations to customers, could be materially and adversely affected.
Weather conditions can adversely affect the Company's operations and revenues and cash flows.
The Company's results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, affect the price of energy commodities, affect the ability to perform services at the construction services and construction materials and contracting businesses and affect ongoing operation and maintenance and construction and drilling activities for the pipeline and energy services and natural gas and oil production businesses. In addition, severe weather can be destructive, causing outages, reduced natural gas and oil production, and/or property damage, which could require additional costs to be incurred. As a result, adverse weather conditions could negatively affect the Company's results of operations, financial condition and cash flows.
Competition is increasing in all of the Company's businesses.
All of the Company's businesses are subject to increased competition. Construction services' competition is based primarily on price and reputation for quality, safety and reliability. The construction materials products are marketed under highly competitive conditions and are subject to such competitive forces as price, service, delivery time and proximity to the customer. The electric utility and natural gas industries also are experiencing increased competitive pressures as a result of consumer demands, technological advances, volatility in natural gas prices and other factors. Pipeline and energy services competes with several pipelines for access to natural gas supplies and gathering, transportation and storage business. The natural gas and oil production business is subject to competition in the acquisition and development of natural gas and oil properties. The increase in competition could negatively affect the Company's results of operations, financial condition and cash flows.
Other factors that could impact the Company's businesses.
The following are other factors that should be considered for a better understanding of the financial condition of the Company. These other factors may impact the Company's financial results in future periods.
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Acquisition, disposal and impairments of assets or facilities
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Changes in operation, performance and construction of plant facilities or other assets
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Changes in present or prospective generation
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The availability of economic expansion or development opportunities
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Population growth rates and demographic patterns
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Market demand for, and/or available supplies of, energy- and construction-related products and services
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The cyclical nature of large construction projects at certain operations
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Changes in tax rates or policies
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Unanticipated project delays or changes in project costs, including related energy costs
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Unanticipated changes in operating expenses or capital expenditures
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Labor negotiations or disputes
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Inability of the various contract counterparties to meet their contractual obligations
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Changes in accounting principles and/or the application of such principles to the Company
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Changes in technology
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Changes in legal or regulatory proceedings
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The ability to effectively integrate the operations and the internal controls of acquired companies
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The ability to attract and retain skilled labor and key personnel
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Increases in employee and retiree benefit costs and funding requirements
ITEM 1B.
ITEM 1B. UNRESOLVED COMMENTS
The Company has no unresolved comments with the SEC.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings of the Company, see Item 8 - Note 20.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of 2008.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company's common stock is listed on the New York Stock Exchange under the symbol "MDU." The price range of the Company's common stock as reported by The Wall Street Journal composite tape during 2008 and 2007 and dividends declared thereon were as follows:
As of December 31, 2008, the Company's common stock was held by approximately 15,600 stockholders of record.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
* Reflects an $84.2 million after-tax noncash write-down of natural gas and oil properties.
Notes:
·
Common stock share amounts reflect the Company's three-for-two common stock splits effected in July 2006 and October 2003.
·
Cascade and Intermountain, natural gas distribution businesses, were acquired on July 2, 2007, and October 1, 2008, respectively. For further information, see Item 8 - Note 2.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
The Company's strategy is to apply its expertise in energy and transportation infrastructure industries to increase market share, increase profitability and enhance shareholder value through:
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Organic growth as well as a continued disciplined approach to the acquisition of well-managed companies and properties
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The elimination of system-wide cost redundancies through increased focus on integration of operations and standardization and consolidation of various support services and functions across companies within the organization
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The development of projects that are accretive to earnings per share and return on invested capital
The Company has capabilities to fund its growth and operations through various sources, including internally generated funds, commercial paper facilities and the issuance from time to time of debt securities and the Company's equity securities. Although volatility and disruptions in the capital markets have recently increased significantly, the Company continues to issue commercial paper to meet its current needs. If access to the commercial paper markets were to become unavailable, the Company may need to borrow under its credit agreements. At this time, accessing the long-term debt market may be more challenging and result in significantly higher interest rates, which has resulted in an increased focus on the use of operating cash flows for capital expenditure purposes. For more information on the Company's net capital expenditures, see Liquidity and Capital Commitments.
The key strategies for each of the Company's business segments and certain related business challenges are summarized below. For a discussion of the Company's business segments, see Item 8 - Note ­16.
Key Strategies and Challenges
Electric and Natural Gas Distribution
Strategy Provide competitively priced energy to customers while working with them to ensure efficient usage. Both the electric and natural gas distribution segments continually seek opportunities for growth and expansion of their customer base through extensions of existing operations and through selected acquisitions of companies and properties at prices that will provide stable cash flows and an opportunity for the Company to earn a competitive return on investment. The natural gas distribution segment also continues to pursue growth by expanding its level of energy-related services.
Challenges Both segments are subject to extensive regulation in the state jurisdictions where they conduct operations with respect to costs and permitted returns on investment as well as subject to certain operational regulations at the federal level. The ability of these segments to grow through acquisitions is subject to significant competition from other energy providers. In addition, the ability of both segments to grow service territory and customer base is affected by the economic environment of the markets served and significant competition from other energy providers, including rural electric cooperatives. The construction of electric generating facilities and transmission lines are subject to increasing costs and lead times, as well as extensive permitting procedures.
Construction Services
Strategy Provide a competitive return on investment while operating in a competitive industry by: building new and strengthening existing customer relationships; effectively controlling costs; retaining, developing and recruiting talented employees; focusing business development efforts on project areas that will permit higher margins; and properly managing risk. This segment continuously seeks opportunities to expand through strategic acquisitions.
Challenges This segment operates in highly competitive markets with many jobs subject to competitive bidding. Maintenance of effective operational and cost controls, retention of key personnel and managing through downturns in the economy are ongoing challenges.
Pipeline and Energy Services
Strategy Leverage the segment's existing expertise in energy infrastructure and related services to increase market share and profitability through optimization of existing operations, internal growth, and acquisitions of energy-related assets and companies. Incremental and new growth opportunities include: access to new sources of natural gas for storage, gathering and transportation services; expansion of existing gathering and transmission facilities; and incremental expansion of pipeline capacity to allow customers access to more liquid and higher-priced markets.
Challenges Challenges for this segment include: energy price volatility; natural gas basis differentials; regulatory requirements; ongoing litigation; recruitment and retention of a skilled workforce; and competition from other natural gas pipeline and gathering companies.
Natural Gas and Oil Production
Strategy Apply technology and leverage existing exploration and production expertise, with a focus on operated properties, to increase production and reserves from existing leaseholds, and to seek additional reserves and production opportunities in new areas to further diversify the segment's asset base. By optimizing existing operations and taking advantage of new and incremental growth opportunities, this segment's goal is to increase both production and reserves over the long term so as to generate competitive returns on investment.
Challenges Volatility in natural gas and oil prices; ongoing environmental litigation and administrative proceedings; timely receipt of necessary permits and approvals; recruitment and retention of a skilled workforce; availability of drilling rigs, materials and auxiliary equipment, and industry-related field services, primarily in a higher price environment; inflationary pressure on development and operating costs; and competition from other natural gas and oil companies are ongoing challenges for this segment.
Construction Materials and Contracting
Strategy Focus on high-growth strategic markets located near major transportation corridors and desirable mid-sized metropolitan areas; strengthen long-term, strategic aggregate reserve position through purchase and/or lease opportunities; enhance profitability through cost containment, margin discipline and vertical integration of the segment's operations; and continue growth through organic and acquisition opportunities. Ongoing efforts to increase margin are being pursued through the implementation of a variety of continuous improvement programs, including corporate purchasing of equipment, parts and commodities (liquid asphalt, diesel fuel, cement and other materials), and negotiation of contract price escalation provisions. Vertical integration allows the segment to manage operations from aggregate mining to final lay-down of concrete and asphalt, with control of and access to adequate quantities of permitted aggregate reserves being
significant. A key element of the Company's long-term strategy for this business is to further expand its presence, through acquisition, in the higher-margin materials business (rock, sand, gravel, liquid asphalt, ready-mixed concrete and related products), complementing and expanding on the Company's expertise.
Challenges The economic downturn has adversely impacted operations, particularly in the private market. This business unit expects to continue cost containment efforts and a greater emphasis on industrial, energy and public works projects. The Company is experiencing significant volatility in the cost of raw materials such as diesel, gasoline, liquid asphalt and steel. Increased competition in certain construction markets has also lowered margins.
For further information on the risks and challenges the Company faces as it pursues its growth strategies and other factors that should be considered for a better understanding of the Company's financial condition, see Item 1A - Risk Factors. For further information on each segment's key growth strategies, projections and certain assumptions, see Prospective Information.
For information pertinent to various commitments and contingencies, see Item 8 - Notes to Consolidated Financial Statements.
Earnings Overview
The following table summarizes the contribution to consolidated earnings by each of the Company's businesses.
2008 compared to 2007 Consolidated earnings for 2008 decreased $138.4 million from the prior year due to:
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The absence in 2008 of income from discontinued operations, net of tax, largely related to the gain on the sale of the Company's domestic independent power production assets and earnings related to an electric generating facility construction project
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An $84.2 million after-tax noncash write-down of natural gas and oil properties as well as higher depreciation, depletion and amortization expense, production taxes and lease operating costs at the natural gas and oil production business
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Decreased earnings at the construction materials and contracting business, primarily construction workloads and margins, as well as product volumes from existing operations, that were significantly lower as a result of the economic downturn
Partially offsetting these decreases were higher average natural gas and oil prices as well as increased oil and natural gas production at the natural gas and oil production business; increased earnings at the natural gas distribution business, largely due to the July 2007 acquisition of Cascade and the October 2008 acquisition of Intermountain; and higher construction workloads at the construction services business.
2007 compared to 2006 Consolidated earnings for 2007 increased $116.3 million from the comparable period largely due to:
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Increased income from discontinued operations, net of tax, largely related to the gain on the sale of the Company's domestic independent power production assets and earnings related to an electric generating facility construction project
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Higher margins, workloads and equipment sales and rentals at the construction services business
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Increased earnings at the natural gas distribution business largely due to the acquisition of Cascade
Partially offsetting the increase were decreased earnings at the construction materials and contracting business, primarily related to decreased volumes and margins resulting from the slowdown in the residential housing sector.
Reflected in the Other category is the negative effect from an income tax adjustment of $9.4 million associated with the anticipated repatriation of profits from Brazilian operations as discussed in Item 8 - Note 15, partially offset by the gain of $6.1 million (after tax) related to the sale of Hartwell, both in 2007.
FINANCIAL AND OPERATING DATA
Below are key financial and operating data for each of the Company's businesses.
Electric
2008 compared to 2007 Electric earnings increased $1.0 million (6 percent) compared to the prior year due to:
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Higher retail sales margins, largely due to the implementation of higher rates in Montana, and increased retail sales volumes of 2 percent
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Increased sales for resale volumes of 35 percent, primarily due to the addition of the wind-powered electric generating station near Baker, Montana, and higher plant availability
Partially offsetting these increases were:
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Higher operation and maintenance expense of $1.7 million (after tax), primarily higher payroll and benefit-related costs, as well as higher scheduled maintenance outage costs at electric generating facilities
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Increased interest expense of $1.2 million (after tax)
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Higher depreciation, depletion and amortization expense of $900,000 (after tax), largely due to higher property, plant and equipment balances
2007 compared to 2006 Electric earnings increased $3.3 million (23 percent) compared to the prior year due to:
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Higher retail sales margins, primarily due to lower demand charges related to a PPA that expired in the fourth quarter of 2006 and increased retail sales volumes of 5 percent
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Decreased operation and maintenance expense of $700,000 (after tax), primarily lower scheduled maintenance outage costs at electric generating stations
Partially offsetting the increase in earnings was lower sales for resale margins due to decreased volumes of 66 percent, largely due to a PPA that expired in the fourth quarter of 2006 and plant availability.
Natural Gas Distribution
2008 compared to 2007 The natural gas distribution business experienced an increase in earnings of $20.8 million (148 percent) compared to the prior year due to:
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Earnings of $18.4 million at Cascade and Intermountain, including a $4.4 million (after tax) gain on the sale of Cascade's natural gas management service, which were acquired on July 2, 2007, and October 1, 2008, respectively
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Increased retail sales volumes from existing operations resulting from colder weather than last year
2007 compared to 2006 The natural gas distribution business experienced an increase in earnings of $8.3 million (147 percent) compared to the prior year due to:
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Earnings of $5.8 million, including a third quarter seasonal loss at Cascade, which was acquired on July 2,
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Increased nonregulated energy-related services of $1.3 million (after tax)
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Decreased operation and maintenance expense, excluding Cascade, of $800,000 (after tax), including the absence in 2007 of the 2006 early retirement program costs
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Increased retail sales volumes resulting from 7 percent colder weather than last year
Construction Services
2008 compared to 2007 Construction services earnings increased $6.0 million (14 percent) compared to the prior year, primarily due to higher construction workloads, largely in the Southwest region. Partially offsetting this increase were lower construction margins in certain regions.
2007 compared to 2006 Construction services earnings increased $16.0 million (57 percent) due to:
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Higher construction margins and workloads of $13.1 million (after tax), largely in the Southwest and Central regions, including industrial-related work
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Increased equipment sales and rentals
Pipeline and Energy Services
2008 compared to 2007 Pipeline and energy services earnings decreased $5.1 million (16 percent) largely due to:
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Lower storage services revenue of $3.1 million (after tax), largely related to lower storage
balances and decreased volumes transported to storage of 31 percent
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Higher operation and maintenance expense, largely related to the natural gas storage litigation as well as higher materials and payroll-related costs. For further information regarding natural gas storage litigation, see Item 8 - Note 20.
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Higher depreciation, depletion and amortization expense of $1.3 million (after tax), largely due to higher property, plant and equipment balances
Partially offsetting these decreases were a 10 percent increase in off-system transportation volumes and demand fees, related to an expansion of the Grasslands system, and $3.0 million (after tax) of higher gathering volumes and rates.
2007 compared to 2006 Pipeline and energy services earnings increased $1.5 million (5 percent) due largely to:
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Higher transportation and gathering volumes ($5.4 million after tax)
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Increased income from discontinued operations of $2.2 million (after tax), related to Innovatum. For further information, see Item 8 - Note 3.
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Increased storage services revenue ($2.2 million after tax)
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Higher gathering rates ($1.4 million after tax)
Partially offsetting this increase in earnings were:
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Absence in 2007 of the benefit from the resolution of a rate proceeding of $4.1 million (after tax) recorded in 2006, which is reflected as a reduction to depreciation, depletion and amortization expense
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Higher operation and maintenance expense, largely due to the natural gas storage litigation, as previously discussed, and higher material costs
The decrease in energy services revenues and purchased natural gas sold reflects the effect of lower natural gas prices.
Natural Gas and Oil Production
2008 compared to 2007 The natural gas and oil production business experienced a decrease in earnings of $20.2 million (14 percent) due to:
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A noncash write-down of natural gas and oil properties of $84.2 million (after tax), as discussed in Item 8 - Note
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Higher depreciation, depletion and amortization expense of $26.6 million (after tax), due to higher depletion rates and increased production
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Higher production taxes of $11.1 million (after tax), primarily due to higher average prices and increased production
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Increased lease operating costs of $9.3 million (after tax), including the East Texas properties acquired in early
Partially offsetting these decreases were:
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Higher average realized natural gas prices of 24 percent
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Higher average realized oil prices of 38 percent
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Increased oil production of 19 percent, largely related to drilling activity in the Bakken area and Paradox Basin as well as production from the East Texas properties
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Increased natural gas production of 4 percent, primarily related to the acquisition of the East Texas properties, as previously discussed
2007 compared to 2006 The natural gas and oil production business experienced a decrease in earnings of $3.2 million (2 percent) due to:
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Increased depreciation, depletion and amortization expense of $12.8 million (after tax) due to higher depletion rates and increased production
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Higher lease operating costs of $8.8 million (after tax), largely CBNG-related and costs related to acquired properties, as well as increased service-related costs
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Lower average realized natural gas prices of 1 percent
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Increased general and administrative expense of $1.9 million (after tax)
Partially offsetting the decrease were:
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Increased oil production of 16 percent resulting from the May 2006 Big Horn acquisition, as well as from the South Texas properties
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Higher average realized oil prices of 17 percent
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Increased natural gas production of 1 percent
Construction Materials and Contracting
2008 compared to 2007 Earnings at the construction materials and contracting business decreased $46.8 million (61 percent) due to decreased construction workloads, margins and product volumes that were significantly lower as a result of the economic downturn, primarily as it relates to the residential market, as well as higher diesel fuel costs at existing operations, which had a combined negative effect on earnings of $53.0 million (after tax). Partially offsetting this decrease were earnings from companies acquired since the comparable prior period, which contributed approximately 8 percent of earnings for 2008.
2007 compared to 2006 Earnings at the construction materials and contracting business decreased $8.7 million (10 percent) due to:
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Decreased earnings of $14.2 million (after tax) from construction, primarily related to the slowdown in the residential housing sector
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Lower earnings from ready-mixed concrete and aggregate operations of $13.8 million (after tax), due to lower volumes and margins related to the slowdown in the residential housing sector
Partially offsetting the decrease were:
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Increased earnings from asphalt and related products of $9.1 million (after tax), due to higher margins
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Decreased general and administrative expense of $5.6 million (after tax), including lower payroll-related costs
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Earnings from companies acquired since the comparable prior period, which contributed approximately 3 percent of earnings for
Other and Intersegment Transactions
Amounts presented in the preceding tables will not agree with the Consolidated Statements of Income due to the Company's other operations and the elimination of intersegment transactions. The amounts relating to these items are as follows:
For further information on intersegment eliminations, see Item 8 - Note 16.
PROSPECTIVE INFORMATION
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 in Item 1A - Risk Factors. Changes in such assumptions and factors could cause actual future results to differ materially from the Company's growth and earnings projections.
MDU Resources Group, Inc.
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Earnings per common share for 2009, diluted, are projected in the range of $1.05 to $1.30.
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The Company expects the percentage of 2009 earnings per common share by quarter to be in the following approximate ranges:
o
First quarter - 15 percent to 20 percent
o
Second quarter - 15 percent to 20 percent
o
Third quarter - 35 percent to 40 percent
o
Fourth quarter - 25 percent to 30 percent
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While 2009 earnings per share is projected to decline compared to 2008 earnings, long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.
Electric
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The Company is negotiating the purchase of an ownership interest of 25 MW in the Wygen III power generation facility near Gillette, Wyoming. If acquired, this owned rate base generation will replace purchased power on its Wyoming system.
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The Company is analyzing potential projects for accommodating load growth and replacing an expired purchased power contract with company-owned generation, which will add to base-load capacity and rate base. The Company is a participant in the Big Stone Station II project. On January 15, 2009, the MNPUC voted to grant a transmission certificate of need and a route permit for the project with conditions. Details of the conditions will be included in the MNPUC's final order expected to be provided by mid-February. If the decision is to proceed with construction of the plant, it is projected to be completed in 2015. The Company anticipates it would own at least 116 MW of this plant. In the event the pending conditions are not acceptable, the Company is reviewing alternatives, including the construction of certain natural gas-fired combustion generation, which would be rate-based.
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On August 20, 2008, Montana-Dakota filed an application with the WYPSC for an electric rate increase, as discussed in Item 8 - Note 19.
Natural gas distribution
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Intermountain was acquired October 1, 2008. For more information regarding the acquisition, see Item 8 - Note 2.
Construction services
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The Company anticipates margins in 2009 to be comparable to 2008.
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The Company continues to focus on costs and efficiencies to enhance margins. With its highly skilled technical workforce, this group is prepared to take advantage of potential future government stimulus spending on transmission infrastructure.
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This business continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.
Pipeline and energy services
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An incremental expansion to the Grasslands Pipeline of 75,000 Mcf per day is in process with an in-service date of August 2009, pending regulatory approval. Through additional compression, the firm capacity of the Grasslands Pipeline will reach ultimate full capacity of 213,000 Mcf per day, an increase from the current firm capacity of 138,000 Mcf per day.
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In 2009, total gathering and transportation throughput is expected to be slightly higher than 2008 record levels.
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The Company continues to pursue expansion of facilities and services offered to customers.
Natural gas and oil production
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As the result of lower natural gas and oil prices, the Company is managing its capital expenditures within its expected operating cash flows. At this level of investment, the Company expects its combined natural gas and oil production in 2009 to be comparable to 2008 levels.
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Earnings guidance reflects estimated natural gas prices for February through December as follows:
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Earnings guidance reflects estimated NYMEX crude oil prices for February through December in the range of $45 to $50 per barrel.
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For 2009, the Company has hedged approximately 40 percent to 45 percent of its estimated natural gas production. For 2010 and 2011, the Company has hedged less than 5 percent of its estimated natural gas production. The hedges that are in place as of February 2, 2009, for 2009 through 2011 are summarized in the following chart:
* 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.
Construction materials and contracting
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The economic slowdown and substantially higher energy prices adversely impacted operations in 2008. Although the Company predicts that this economic slowdown will continue into 2009, it is expected that earnings will be higher than 2008 primarily the result of cost reduction measures put in place during 2008 and substantially lower diesel costs expected in 2009 compared to 2008.
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The Company continues its strong emphasis on cost containment throughout the organization. In addition, the Company has strong market share in its markets and is well positioned to take advantage of potential future government stimulus spending on transportation infrastructure.
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The Company also is pursuing opportunities for expansion of its liquid asphalt materials business to cost effectively meet the liquid asphalt requirements of the Company, as well as third-party customers.
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Backlog of $453 million at December 31, 2008, includes the recent addition of several public works projects. Although public project margins tend to be somewhat lower than private construction-related work, the Company anticipates significant contributions to revenue from an increase in public works volume.
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As the country’s 8th largest aggregate producer, the Company will continue to strategically manage its aggregate reserves in all its markets.
NEW ACCOUNTING STANDARDS
For information regarding new accounting standards, see Item 8 - Note 1, which is incorporated by reference.
CRITICAL ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The Company has prepared its financial statements in conformity with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities, at the date of the financial statements as well as the reported amounts of revenues and expenses during the reporting period. The Company's significant accounting policies are discussed in Item 8 - Note 1.
Estimates are used for items such as impairment testing of long-lived assets, goodwill and natural gas and oil properties; fair values of acquired assets and liabilities under the purchase method of accounting; natural gas and oil reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. The Company's critical accounting policies are subject to judgments and uncertainties that affect the application of such policies. As discussed below, the Company's financial position or results of operations may be materially different when reported under different conditions or when using different assumptions in the application of such policies.
As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. The following critical accounting policies involve significant judgments and estimates.
Impairment of long-lived assets and intangibles
The Company reviews the carrying values of its long-lived assets and intangibles, excluding natural gas and oil properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable and annually for goodwill. Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows could negatively affect the fair value of the Company's assets and result in an impairment charge. If an impairment indicator exists for tangible and intangible assets, excluding goodwill, the asset group held and used is tested for recoverability by comparing an estimate of undiscounted future cash flows attributable to the assets compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. In the case of goodwill, the first step, used to identify a potential impairment, compares the fair value of the reporting unit using discounted cash flows, with its carrying amount, including goodwill. The second step, used to measure the amount of the impairment loss if step one indicates a potential impairment, compares the implied fair value of the reporting unit goodwill with the carrying amount of goodwill.
Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties. The Company uses critical estimates and assumptions when testing assets for impairment, including present value techniques based on estimates of cash flows, quoted market prices or valuations by third parties, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.
There is risk involved when determining the fair value of assets, tangible and intangible, as there may be unforeseen events and changes in circumstances and market conditions and changes in estimates of future cash flows.
The Company believes its estimates used in calculating the fair value of long-lived assets, including goodwill and identifiable intangibles, are reasonable based on the information that is known when the estimates are made.
Natural gas and oil properties
The Company uses the full-cost method of accounting for its natural gas and oil production activities. Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves based on spot market prices that exist at the end of the period discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties less applicable income taxes. The Company hedges a portion of its natural gas and oil production and the effects of the cash flow hedges are used in determining the full-cost ceiling. Judgments and assumptions are made when estimating and valuing reserves. There is risk that sustained downward movements in natural gas and oil prices, changes in estimates of reserve quantities and changes in operating and development costs could result in future noncash write-downs of the Company's natural gas and oil properties.
Estimates of reserves are arrived at using actual historical wellhead production trends and/or standard reservoir engineering methods utilizing available engineering and geologic data derived from well tests. Other factors used in the reserve estimates are current natural gas and oil prices, current estimates of well operating and future development costs, and the interest owned by the Company in the well. These estimates are refined as new information becomes available.
Historically, the Company has not had any material revisions to its reserve estimates. As a result, the Company has not changed its practice in estimating reserves and does not anticipate changing its methodologies in the future.
Revenue recognition
Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The recognition of revenue in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of revenue. Critical estimates related to the recognition of revenue include the accumulated provision for revenues subject to refund and costs on construction contracts under the percentage-of-completion method.
Estimates for revenues subject to refund are established initially for each regulatory rate proceeding and are subject to change depending on the applicable regulatory agency's (Agency) approval of final rates. These estimates are based on the Company's analysis of its as-filed application compared to previous Agency decisions in prior rate filings by the Company and other regulated companies. The Company periodically reviews the status of its outstanding regulatory proceedings and liability assumptions and may from time to time change its liability estimates subject to known developments as the regulatory proceedings move through the regulatory review process. The accuracy of the estimates is ultimately determined when the Agency issues its final ruling on each regulatory proceeding for which revenues were subject to refund. Estimates have changed from time to time as additional information has become available as to what the ultimate
outcome may be and will likely continue to change in the future as new information becomes available on each outstanding regulatory proceeding that is subject to refund.
The Company recognizes construction contract revenue from fixed-price and modified fixed-price construction contracts at its construction businesses using the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract. This method depends largely on the ability to make reasonably dependable estimates related to the extent of progress toward completion of the contract, contract revenues and contract costs. Inasmuch as contract prices are generally set before the work is performed, the estimates pertaining to every project could contain significant unknown risks such as volatile labor, material and fuel costs, weather delays, adverse project site conditions, unforeseen actions by regulatory agencies, performance by subcontractors, job management and relations with project owners.
Several factors are evaluated in determining the bid price for contract work. These include, but are not limited to, the complexities of the job, past history performing similar types of work, seasonal weather patterns, competition and market conditions, job site conditions, work force safety, reputation of the project owner, availability of labor, materials and fuel, project location and project completion dates. As a project commences, estimates are continually monitored and revised as information becomes available and actual costs and conditions surrounding the job become known.
The Company believes its estimates surrounding percentage-of-completion accounting are reasonable based on the information that is known when the estimates are made. The Company has contract administration, accounting and management control systems in place that allow its estimates to be updated and monitored on a regular basis. Because of the many factors that are evaluated in determining bid prices, it is inherent that the Company's estimates have changed in the past and will continually change in the future as new information becomes available for each job.
Purchase accounting
The Company accounts for its acquisitions under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed are recorded at their respective fair values. The excess of the purchase price over the fair value of the assets acquired and liabilities assumed is recorded as goodwill. The recorded values of assets and liabilities are based in part on third-party estimates and valuations when available. The remaining values are based on management's judgments and estimates, and, accordingly, the Company's financial position or results of operations may be affected by changes in estimates and judgments.
Acquired assets and liabilities assumed by the Company that are subject to critical estimates include property, plant and equipment and intangibles.
The fair value of owned aggregate reserves is determined using qualified internal personnel as well as geologists. Reserve estimates are calculated based on the best available data. This data is collected from drill holes and other subsurface investigations as well as investigations of surface features such as mine highwalls and other exposures of the aggregate reserves. Mine plans, production history and geologic data are also used to estimate reserve quantities. Value is assigned to the aggregate reserves based on a review of market royalty rates, expected cash flows and the number of years of aggregate reserves at owned aggregate sites.
The fair value of property, plant and equipment is based on a valuation performed either by qualified internal personnel and/or outside appraisers. Fair values assigned to plant and equipment are based on several factors including the age and condition of the equipment, maintenance records of the equipment and auction values for equipment with similar characteristics at the time of purchase.
The fair value of leasehold rights is based on estimates including royalty rates, lease terms and other discernible factors for acquired leasehold rights, and estimated cash flows.
While the allocation of the purchase price of an acquisition is subject to a considerable degree of judgment and uncertainty, the Company does not expect the estimates to vary significantly once an acquisition has been completed. The Company believes its estimates have been reasonable in the past as there have been no significant valuation adjustments subsequent to the final allocation of the purchase price to the acquired assets and liabilities. In addition, goodwill impairment testing is performed annually in accordance with SFAS No. 142.
Asset retirement obligations
Entities are required to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company has recorded obligations related to the plugging and abandonment of natural gas and oil wells, decommissioning of certain electric generating facilities, reclamation of certain aggregate properties, special handling and disposal of hazardous materials at certain electric generating facilities, natural gas distribution and transmission facilities and buildings and certain other obligations associated with leased properties.
The liability for future asset retirement obligations bears the risk of change as many factors go into the development of the estimate of these obligations and the likelihood that over time these factors can and will change. Factors used in the estimation of future asset retirement obligations include estimates of current retirement costs, future inflation factors, life of the asset and discount rates. These factors determine both a present value of the retirement liability and the accretion to the retirement liability in subsequent years.
Long-lived assets are reviewed to determine if a legal retirement obligation exists. If a legal retirement obligation exists, a determination of the liability is made if a reasonable estimate of the present value of the obligation can be made. The present value of the retirement obligation is calculated by inflating current estimated retirement costs of the long-lived asset over its expected life to determine the expected future cost and then discounting the expected future cost back to the present value using a discount rate equal to the credit-adjusted risk-free interest rate in effect when the liability was initially recognized.
These estimates and assumptions are subject to a number of variables and are expected to change in the future. Estimates and assumptions will change as the estimated useful lives of the assets change, the current estimated retirement costs change, new legal retirement obligations occur and/or as existing legal asset retirement obligations, for which a reasonable estimate of fair value could not initially be made because of the range of time over which the Company may settle the obligation is unknown or cannot be estimated, become less uncertain and a reasonable estimate of the future liability can be made.
Pension and other postretirement benefits
The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to these plans. Costs of providing pension and other postretirement benefits bear the risk of change, as they are dependent upon numerous factors based on assumptions of future conditions.
The Company makes various assumptions when determining plan costs, including the current discount rates and the expected long-term return on plan assets, the rate of compensation increases and healthcare cost trend rates. In selecting the expected long-term return on plan assets, which is considered to be one of the key variables in determining benefit expense or income, the Company considers historical returns, current market conditions and expected future market trends, including changes in interest rates and equity and bond market performance. Another key variable in determining benefit expense or income is the discount rate. In selecting the discount rate, the Company matches forecasted future cash flows of the pension and postretirement plans to a yield curve which consists of a hypothetical portfolio of high-quality corporate bonds with varying maturity dates, as well as other factors, as a basis. The Company's pension and other postretirement benefit plan assets are primarily made up of equity and fixed-income investments. Fluctuations in actual equity and bond market returns as well as changes in general interest rates may result in increased or decreased pension and other postretirement benefit costs in the future. Management estimates the rate of compensation increase based on long-term assumed wage increases and the healthcare cost trend rates are determined by historical and future trends.
The Company believes the estimates made for its pension and other postretirement benefits are reasonable based on the information that is known when the estimates are made. These estimates and assumptions are subject to a number of variables and are expected to change in the future. Estimates and assumptions will be affected by changes in the discount rate, the expected long-term return on plan assets, the rate of compensation increase and healthcare cost trend rates. The Company plans to continue to use its current methodologies to determine plan costs.
Income taxes
Income taxes require significant judgments and estimates including the determination of income tax expense, deferred tax assets and liabilities and, if necessary, any valuation allowances that may be required for deferred tax assets and accruals for uncertain tax positions. The effective income tax rate is subject to variability from period to period as a result of changes in federal and state income tax rates and/or changes in tax laws. In addition, the effective tax rate may be affected by other changes including the allocation of property, payroll and revenues between states.
The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities resulting from the Company's adoption of SFAS No. 109 have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.
The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.
The Company accounts for uncertain tax positions in accordance with FIN 48. FIN 48 establishes standards for measurement and recognition in financial statements of tax positions taken or expected to be taken in an income tax return. Under FIN 48, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.
The Company believes its estimates surrounding income taxes are reasonable based on the information that is known when the estimates are made.
LIQUIDITY AND CAPITAL COMMITMENTS
Cash flows
Operating activities The changes in cash flows from operating activities generally follow the results of operations as discussed in Financial and Operating Data and also are affected by changes in working capital.
Cash flows provided by operating activities in 2008 increased $223.0 million from the comparable prior period, due to:
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Higher income from continuing operations before depreciation, depletion and amortization and before the after-tax noncash write-down of natural gas and oil properties
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Absence of cash flows used related to discontinued operations in 2007 of $71.4 million
Cash flows provided by operating activities in 2007 decreased $96.4 million from the comparable prior period, the result of:
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Increased cash flows used related to discontinued operations of $104.9 million, largely due to an increase in quarterly income tax payments due to the gain on the sale of the domestic independent power production assets
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Increased working capital requirements of $59.2 million, largely due to higher cash needs for receivables at the natural gas distribution business, including the effects of the acquisition of Cascade and fluctuations in natural gas prices
Partially offsetting the decrease in cash flows from operating activities were:
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Higher depreciation, depletion and amortization expense of $45.4 million, largely at the natural gas and oil production business
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Higher deferred income taxes of $28.6 million, largely related to expenditures at the natural gas and oil production business and the effect from an income tax adjustment associated with the anticipated repatriation of profits from Brazilian operations as discussed in Item 8 - Note ­­15.
Investing activities Cash flows used in investing activities in 2008 increased $765.1 million from the comparable prior period due to:
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Absence of cash flows provided by discontinued operations in 2007 of $548.2 million, primarily the result of the sale of the domestic independent power production assets in the third quarter of
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Increased ongoing capital expenditures of $188.2 million, largely at the natural gas and oil production business
·
Higher cash used in connection with acquisitions, net of cash acquired, of $185.1 million, largely due to the acquisition of Intermountain and natural gas and oil producing properties in East Texas in 2008, partially offset by the absence of the 2007 acquisition of Cascade
Partially offsetting the increase in cash flows used in investing activities were higher proceeds from investments of $85.8 million in 2008, as well as the absence of cash used for investments of $67.1 million in 2007.
Cash flows used in investing activities in 2007 decreased $318.0 million compared to the comparable prior period, the result of:
·
An increase in cash flows provided by discontinued operations of $586.1 million, primarily the result of the sale of the domestic independent power production assets in the third quarter of
·
Increased proceeds from the sale of equity method investments of $58.5 million, primarily the result of the sale of the Trinity Generating Facility in the first quarter of 2007 and Hartwell in the third quarter of
Partially offsetting the decrease in cash flows used in investing activities were:
·
An increase in cash flows used for acquisitions, net of cash acquired, of $234.7 million, largely the result of the Cascade acquisition
·
Higher ongoing capital expenditures, including expenditures related to a wind electric generation project at the electric business
Financing activities Cash flows provided by financing activities in 2008 increased $456.2 million from the comparable prior period, primarily due to higher issuance of long-term debt of $333.7 million as well as higher net short-term borrowings of $101.7 million, largely related to higher ongoing capital expenditures and acquisitions.
Cash flows used in financing activities in 2007 increased $158.4 million compared to the comparable prior period, primarily the result of a decrease in the issuance of long-term debt of $236.1 million, partially offset by lower repayments of long-term debt of $83.0 million. Also reflected in cash flows from financing activities was the issuance and subsequent repayment of short-term borrowings of $310.0 million from the term loan agreement entered into in connection with the funding of the Cascade acquisition.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit pension plans (Pension Plans) for certain employees. Plan assets consist of investments in equity and fixed-income securities. Various actuarial assumptions are used in calculating the benefit expense (income) and liability (asset) related to the Pension Plans. Actuarial assumptions include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by the Company within certain guidelines. At December 31, 2008, certain Pension Plans' accumulated benefit obligations exceeded these plans' assets by approximately $85.9 million. Pretax pension expense reflected in the years ended December 31, 2008, 2007 and 2006, was $4.6 million, $6.5 million and $7.0 million, respectively. The Company's pension expense is currently projected to be approximately $4.5 million to $5.5 million in 2009. Funding for the Pension Plans is
actuarially determined. The minimum required contributions for 2008, 2007 and 2006 were approximately $6.8 million, $1.8 million and $2.6 million, respectively. For further information on the Company's Pension Plans, see Item 8 - Note 17.
Capital expenditures
The Company's capital expenditures for 2006 through 2008 and as anticipated for 2009 through 2011 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term debt.
Capital expenditures for 2008, 2007 and 2006, in the preceding table include noncash transactions, including the issuance of the Company's equity securities, in connection with acquisitions and the outstanding indebtedness related to the 2008 Intermountain acquisition and the 2007 Cascade acquisition. The noncash transactions were $97.6 million in 2008, $217.3 million in 2007 and immaterial in 2006.
In 2008, the Company acquired a construction services business in Nevada; natural gas properties in Texas; construction materials and contracting businesses in Alaska, California, Idaho and Texas; and Intermountain, a natural gas distribution business. The total purchase consideration for these businesses and properties and purchase price adjustments with respect to certain other acquisitions made prior to 2008, consisting of the Company's common stock and cash and the outstanding indebtedness of Intermountain, was $624.5 million.
The 2008 capital expenditures, including those for the previously mentioned acquisitions and retirements of long-term debt, were met from internal sources, the issuance of long-term debt and the Company's equity securities. Estimated capital expenditures for the years 2009 through 2011 include those for:
·
System upgrades
·
Routine replacements
·
Service extensions
·
Routine equipment maintenance and replacements
·
Buildings, land and building improvements
·
Pipeline and gathering projects
·
Further enhancement of natural gas and oil production and reserve growth
·
Power generation opportunities, including certain costs for additional electric generating capacity
·
Other growth opportunities
The Company continues to evaluate potential future acquisitions and other growth opportunities; however, they are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the estimates in the preceding table. It is anticipated that all of the funds required for capital expenditures and retirement of long-term debt for the years 2009 through 2011 will be met from various sources, including internally generated funds; the Company's credit facilities, as described below; and through the issuance of long-term debt and the Company's equity securities.
Capital resources
Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2008.
MDU Resources Group, Inc. The Company has a revolving credit agreement with various banks totaling $125 million (with provision for an increase, at the option of the Company on stated conditions, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement at December 31, 2008. The credit agreement supports the Company's $125 million commercial paper program. Although volatility in the capital markets has recently increased significantly, the Company continues to issue commercial paper to meet its current needs. Under the Company's commercial paper program, $22.5 million was outstanding at December 31, 2008. The commercial paper borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings (supported by the credit agreement, which expires in June 2011).
The Company's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. Minor fluctuations in the Company's credit ratings have not limited, nor would they be expected to limit, the Company's ability to access the capital markets. In the event of a minor downgrade, the Company may experience a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If the Company were to experience a significant downgrade of its credit ratings, it may need to borrow under its credit agreement.
Prior to the maturity of the credit agreement, the Company expects that it will negotiate the extension or replacement of this agreement. If the Company is unable to successfully negotiate an
extension of, or replacement for, the credit agreement, or if the fees on this facility became too expensive, which the Company does not currently anticipate, the Company would seek alternative funding.
In order to borrow under the Company's credit agreement, the Company must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of the Company's credit agreement, see Item 8 - Note 10.
In connection with the funding of the Intermountain acquisition, on September 26, 2008, the Company entered into a term loan agreement providing for a commitment amount of $175 million. On October 1, 2008, the Company borrowed $170 million under this agreement, which expires on March 24, 2009. There was $57.0 million outstanding under the term loan agreement on December 31, 2008. The agreement contains customary covenants and default provisions. For information on the covenants and certain other conditions of the Company’s term loan agreement, see Item 8 - Note 9.
There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries.
The Company's issuance of first mortgage debt is subject to certain restrictions imposed under the terms and conditions of its Mortgage. Generally, those restrictions require the Company to fund $1.43 of unfunded property or use $1.00 of refunded bonds for each dollar of indebtedness incurred under the Mortgage and, in some cases, to certify to the trustee that annual earnings (pretax and before interest charges), as defined in the Mortgage, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the tests, as of December 31, 2008, the Company could have issued approximately $620 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred dividends was 5.3 times and 6.4 times for the 12 months ended December 31, 2008 and 2007, respectively. Common stockholders' equity as a percent of total capitalization was 61 percent and 66 percent at December 31, 2008 and 2007, respectively.
The Company has repurchased, and may from time to time seek to repurchase, outstanding first mortgage bonds through open market purchases or privately negotiated transactions. The Company will evaluate any such transactions in light of then existing market conditions, taking into account its liquidity and prospects for future access to capital. As of December 31, 2008, the Company had $35.5 million of first mortgage bonds outstanding, $30.0 million of which were held by the Indenture trustee for the benefit of the senior note holders. The aggregate principal amount of the Company's outstanding first mortgage bonds, other than those held by the Indenture trustee, is $5.5 million and satisfies the lien release requirements under the Indenture. As a result, the Company may at any time, subject to satisfying certain specified conditions, require that any debt issued under its Indenture become unsecured and rank equally with all of the Company's other unsecured and unsubordinated debt (as of December 31, 2008, the only such debt outstanding under the Indenture was $30.0 million in aggregate principal amount of the Company's 5.98% Senior Notes due in 2033).
On September 5, 2008, the Company entered into a Sales Agency Financing Agreement with Wells Fargo Securities, LLC with respect to the issuance and sale of up to 5,000,000 shares of the Company's common stock. The common stock may be offered for sale, from time to time, in
accordance with the terms and conditions of the agreement, which terminates on May 28, 2011. Proceeds from the sale of shares of common stock under the agreement are expected to be used for corporate development purposes and other general corporate purposes. The Company has not issued any stock under the Sales Agency Financing Agreement through December 31, 2008.
On May 28, 2008, the company filed a registration statement with the SEC, pursuant to Rule 415 under the Securities Act, relating to the possible issuance from time to time of common stock or debt securities of the Company. The amount of securities issuable by the Company is established from time to time by its board of directors. At December 31, 2008, the Company's board of directors had authorized the issuance of up to an aggregate offering price of $1.0 billion of registered securities. The Company may sell all or a portion of such securities if warranted by market conditions and the Company's capital requirements. Any offer and sale of such securities will be made only by means of a prospectus meeting the requirements of the Securities Act and the rules and regulations thereunder.
MDU Energy Capital, LLC On October 1, 2008, MDU Energy Capital entered into an amendment to its master shelf agreement which increased the facility amount from $125 million to $175 million. Under the terms of the master shelf agreement, $165.0 million was outstanding at December 31, 2008. MDU Energy Capital may incur additional indebtedness under the master shelf agreement until the earlier of August 14, 2010, or such time as the agreement is terminated by either of the parties thereto.
On October 1, 2008, MDU Energy Capital borrowed $80.0 million under the agreement. The indebtedness consists of $30 million of senior notes due October 1, 2013, and $50 million of senior notes due October 1, 2015. MDU Energy Capital used the proceeds from the borrowing to pay a dividend to the Company which, in turn, used this dividend to partially fund the acquisition of Intermountain, as previously discussed.
In order to borrow under its master shelf agreement, MDU Energy Capital must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of the MDU Energy Capital master shelf agreement, see Item 8 - Note 10.
Cascade Natural Gas Corporation Cascade has a revolving credit agreement with various banks totaling $50 million with certain provisions allowing for increased borrowings, up to a maximum of $75 million. The $50 million credit agreement expires on December 28, 2012, with provisions allowing for an extension of up to two years upon consent of the banks. Cascade also has a revolving credit agreement totaling $15 million, which expires on March 11, 2009. Under the terms of the $50 million credit agreement, $48.1 million was outstanding at December 31, 2008. There was no amount outstanding under the $15 million credit agreement at December 31, 2008. As of December 31, 2008, there were outstanding letters of credit, as discussed in Item 8 - Note 20, of which $1.9 million reduced amounts available under the $50 million credit agreement.
In order to borrow under Cascade's credit agreements, Cascade must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of Cascade's credit agreements, see Item 8 - Note 9.
Cascade's credit agreements contain cross-default provisions. For more information on the cross-default provisions of this agreement, see Item 8 - Note 9.
Intermountain Gas Company Intermountain has a revolving credit agreement with various banks totaling $65 million with certain provisions allowing for increased borrowings, up to a maximum of $70 million. The credit agreement expires on August 31, 2010. Under the terms of the credit agreement, $36.5 million was outstanding at December 31, 2008.
In order to borrow under Intermountain's credit agreement, Intermountain must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of Intermountain's credit agreement, see Item 8 - Note 10.
Intermountain's credit agreement contains cross-default provisions. For more information on the cross-default provisions of this agreement, see Item 8 - Note 10.
Centennial Energy Holdings, Inc. Centennial has a revolving credit agreement with various banks and institutions totaling $400 million with certain provisions allowing for increased borrowings. The credit agreement supports Centennial's $400 million commercial paper program. Although volatility in the capital markets has recently increased significantly, the Company continues to issue commercial paper to meet its current needs. There were no outstanding borrowings under the Centennial credit agreement at December 31, 2008. Under the Centennial commercial paper program, $150.0 million was outstanding at December 31, 2008. The Centennial commercial paper borrowings are classified as long-term debt as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings (supported by the Centennial credit agreement). The revolving credit agreement includes a provision for an increase, at the option of Centennial on stated conditions, up to a maximum of $450 million and expires on December 13, 2012. As of December 31, 2008, Centennial had letters of credit outstanding, as discussed in Item 8 - Note 20, of which $24.3 million reduced amounts available under the agreement.
Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $550 million. Under the terms of the master shelf agreement, $509.0 million was outstanding at December 31, 2008. The ability to request additional borrowings under this master shelf agreement expires on May 8, 2009. To meet potential future financing needs, Centennial may pursue other financing arrangements, including private and/or public financing.
Centennial's objective is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. In the event of a downgrade, Centennial may experience an increase in overall interest rates with respect to its cost of borrowings and may need to borrow under its committed bank lines.
Prior to the maturity of the Centennial credit agreements, Centennial expects that it will negotiate the extension or replacement of these agreements, which provide credit support to access the capital markets. In the event Centennial was unable to successfully negotiate these agreements, or in the event the fees on such facilities became too expensive, which Centennial does not currently anticipate, it would seek alternative funding.
In order to borrow under Centennial's credit agreement and the Centennial uncommitted long-term master shelf agreement, Centennial and certain of its subsidiaries must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of the credit agreement and the uncommitted long-term master shelf agreement, see Item 8 - Note 10.
Certain of Centennial's financing agreements contain cross-default provisions. For more information on the cross-default provisions of these agreements, see Item 8 - Note 10.
Williston Basin Interstate Pipeline Company In December 2008, Williston Basin entered into an uncommitted long-term private shelf agreement that allows for borrowings up to $125 million. Under the terms of the private shelf agreement, $72.5 million was outstanding at December 31, 2008. The $72.5 million outstanding consists of $20.0 million of notes issued under the private shelf agreement and $52.5 million of notes issued under a master shelf agreement that expired on December 20, 2008. The ability to request additional borrowings under this private shelf agreement expires on December 23, 2010, with certain provisions allowing for an extension to December 23, 2011.
In order to borrow under its uncommitted long-term private shelf agreement, Williston Basin must be in compliance with the applicable covenants and certain other conditions. For information on the covenants and certain other conditions of the uncommitted long-term private shelf agreement, see Item 8 - Note 10.
Off balance sheet arrangements
In connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent of any losses that Petrobras may incur from certain contingent liabilities specified in the purchase agreement. For more information, see Item 8 - Note 20.
Centennial continues to guarantee CEM’s obligations under a construction contract for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. For more information, see Item 8 - Note 20.
Contractual obligations and commercial commitments
For more information on the Company's contractual obligations on long-term debt, operating leases, purchase commitments and uncertain tax positions, see Item 8 - Notes 10, 15 and 20. At December 31, 2008, the Company's commitments under these obligations were as follows:
Not reflected in the table above are $5.6 million in uncertain tax positions for which the year of settlement is not reasonably possible to determine.
EFFECTS OF INFLATION
Inflation did not have a significant effect on the Company's operations in 2008, 2007 or 2006.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to the impact of market fluctuations associated with commodity prices, interest rates and foreign currency. The Company has policies and procedures to assist in controlling these market risks and utilizes derivatives to manage a portion of its risk.
For more information on derivatives and the Company's derivative policies and procedures, see Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of MDU Resources Group, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. The Company's internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.
Based on our evaluation under the framework in Internal Control-Integrated Framework, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2008.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2008, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.
/s/ Terry D. Hildestad
/s/ Vernon A. Raile
Terry D. Hildestad
Vernon A. Raile
President and Chief Executive Officer
Executive Vice President, Treasurer and
Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF MDU RESOURCES GROUP, INC.:
We have audited the accompanying consolidated balance sheets of MDU Resources Group, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule for each of the three years in the period ended December 31, 2008, listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MDU Resources Group, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 11, 2009, expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 11, 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF MDU RESOURCES GROUP, INC.:
We have audited the internal control over financial reporting of MDU Resources Group, Inc. and subsidiaries (the “Company”) as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2008, of the Company and our report dated February 11, 2009, expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 11, 2009
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation
The consolidated financial statements of the Company include the accounts of the following businesses: electric, natural gas distribution, construction services, pipeline and energy services, natural gas and oil production, construction materials and contracting, and other. The electric, natural gas distribution, and pipeline and energy services businesses are substantially all regulated. Construction services, natural gas and oil production, construction materials and contracting, and other are nonregulated. For further descriptions of the Company's businesses, see Note 16. The statements also include the ownership interests in the assets, liabilities and expenses of two jointly owned electric generating facilities.
The Company's regulated businesses are subject to various state and federal agency regulations. The accounting policies followed by these businesses are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by the Company's nonregulated businesses.
The Company's regulated businesses account for certain income and expense items under the provisions of SFAS No. 71. SFAS No. 71 requires these businesses to defer as regulatory assets or liabilities certain items that would have otherwise been reflected as expense or income, respectively, based on the expected regulatory treatment in future rates. The expected recovery or flowback of these deferred items generally is based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are being amortized consistently with the regulatory treatment established by the FERC and the applicable state public service commissions. See Note 6 for more information regarding the nature and amounts of these regulatory deferrals.
Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses.
Cash and cash equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of December 31, 2008 and 2007, was $13.7 million and $14.6 million, respectively.
Natural gas in storage
Natural gas in storage for the Company's regulated operations is generally carried at cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories and was $27.6 million and $28.8 million at December 31, 2008 and 2007, respectively. The remainder of natural gas in storage, which largely represents the cost of the gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $43.4 million and $43.0 million at December 31, 2008 and 2007, respectively.
Inventories
Inventories, other than natural gas in storage for the Company's regulated operations, consisted primarily of aggregates held for resale of $89.1 million and $102.2 million, materials and supplies
of $92.4 million and $56.0 million, and other inventories of $52.4 million and $42.3 million, as of December 31, 2008 and 2007, respectively. These inventories were stated at the lower of average cost or market value.
Investments
The Company's investments include its equity method investments as discussed in Note 4, the cash surrender value of life insurance policies, investments in fixed-income and equity securities and auction rate securities. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. On January 1, 2008, upon the adoption of SFAS No. 159, the Company elected to measure its investments in certain fixed-income and equity securities at fair value with any unrealized gains and losses recorded on the Consolidated Statements of Income. Prior to the adoption of SFAS No. 159, the Company's fixed-income and equity securities were accounted for as available-for-sale investments in accordance with SFAS No. 115. In accordance with SFAS No. 115, these investments were recorded at fair value with any unrealized gains and losses, net of income taxes, recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets until realized. The Company accounts for auction rate securities as available-for-sale in accordance with SFAS No. 115. For more information, see Notes 8 and 17 and comprehensive income in this note.
Property, plant and equipment
Additions to property, plant and equipment are recorded at cost. When regulated assets are retired, or otherwise disposed of in the ordinary course of business, the original cost of the asset is charged to accumulated depreciation. With respect to the retirement or disposal of all other assets, except for natural gas and oil production properties as described in natural gas and oil properties in this note, the resulting gains or losses are recognized as a component of income. The Company is permitted to capitalize AFUDC on regulated construction projects and to include such amounts in rate base when the related facilities are placed in service. In addition, the Company capitalizes interest, when applicable, on certain construction projects associated with its other operations. The amount of AFUDC and interest capitalized was $9.0 million, $7.1 million and $5.8 million in 2008, 2007 and 2006, respectively. Generally, property, plant and equipment are depreciated on a straight-line basis over the average useful lives of the assets, except for depletable aggregate reserves, which are depleted based on the units-of-production method, and natural gas and oil production properties, which are amortized on the units-of-production method based on total reserves.
Property, plant and equipment at December 31 was as follows:
* * Amortized on the units-of-production method based on total proved reserves at an Mcf equivalent average rate of $2.00, $1.59 and $1.38 for the years ended December 31, 2008, 2007 and 2006, respectively. Includes natural gas and oil production properties accounted for under the full-cost method, of which $232.1 million and $142.5 million were excluded from amortization at December 31, 2008 and 2007, respectively.
** Depleted on the units-of-production method.
Impairment of long-lived assets
The Company reviews the carrying values of its long-lived assets, excluding goodwill and natural gas and oil properties, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. No significant impairment losses were recorded in 2008, 2007 and 2006. Unforeseen events and changes in circumstances could require the recognition of other impairment losses at some future date.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired. For more information on goodwill impairments and goodwill, see Notes 3 and 5.
Natural gas and oil properties
The Company uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, all costs incurred in the acquisition, exploration and development of natural gas and oil properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized. Capitalized costs are subject to a "ceiling test" that limits such costs to the aggregate of the present value of future net cash flows from proved reserves based on spot market prices that exist at the end of the period discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties less applicable income taxes. Future net revenue is estimated based on end-of-quarter spot market prices adjusted for contracted price changes. If capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter unless subsequent price changes eliminate or reduce an indicated write-down.
Due to low natural gas and oil prices that existed on December 31, 2008, the Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at December 31, 2008. Accordingly, the Company was required to write down its natural gas and oil producing properties. The noncash write-down amounted to $135.8 million ($84.2 million after tax) for the year ended December 31, 2008. Prices subsequent to December 31, 2008, remained low and therefore the noncash write-down was not reduced or eliminated. Sustained downward movements in natural gas and oil prices subsequent to December 31, 2008, could result in future write-downs of the Company's natural gas and oil properties.
The Company hedges a portion of its natural gas and oil production and the effects of the cash flow hedges were used in determining the full-cost ceiling. The Company would have recognized an additional write-down of its natural gas and oil properties of $79.2 million ($49.1 million after tax) if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 7.
The following table summarizes the Company's natural gas and oil properties not subject to amortization at December 31, 2008, in total and by the year in which such costs were incurred:
Costs not subject to amortization as of December 31, 2008, consisted primarily of unevaluated leaseholds, drilling costs, seismic costs and capitalized interest associated primarily with oil and gas development in the Paradox Basin in Utah; Bakken area in western North Dakota; Big Horn Basin in Wyoming; south Texas properties; CBNG in the Powder River Basin of Wyoming and Montana; and the newly acquired properties in eastern Texas. The Company expects that the majority of these costs will be evaluated within the next five years and included in the amortization base as the properties are evaluated and/or developed.
Revenue recognition
Revenue is recognized when the earnings process is complete, as evidenced by an agreement between the customer and the Company, when delivery has occurred or services have been rendered, when the fee is fixed or determinable and when collection is reasonably assured. The Company recognizes utility revenue each month based on the services provided to all utility customers during the month. Accrued unbilled revenue which is included in receivables, net, represents revenues recognized in excess of amounts billed. Accrued unbilled revenue at Montana-Dakota, Cascade and Intermountain was $123.2 million at December 31, 2008. Accrued unbilled revenue at Montana-Dakota and Cascade was $66.6 million at December 31, 2007. The Company recognizes construction contract revenue at its construction businesses using the percentage-of-completion method as discussed later. The Company recognizes revenue from natural gas and oil production properties only on that portion of production sold and allocable to the Company's ownership interest in the related well. The Company recognizes all other revenues when services are rendered or goods are delivered.
Percentage-of-completion method
The Company recognizes construction contract revenue from fixed-price and modified fixed-price construction contracts at its construction businesses using the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract. If a loss is anticipated on a contract, the loss is immediately recognized. Costs in excess of billings on uncompleted contracts of $40.1 million and $45.2 million at December 31, 2008 and 2007, respectively, represent revenues recognized in excess of amounts billed and were included in receivables, net. Billings in excess of costs on uncompleted contracts of $106.9 million and $81.4 million at December 31, 2008 and 2007, respectively, represent billings in excess of revenues recognized and were included in accounts payable. Amounts representing balances billed but not paid by customers under retainage provisions in contracts amounted to $86.9 million and $80.3 million at December 31, 2008 and 2007, respectively. The amounts expected to be paid within one year or less are included in receivables, net, and amounted to $67.7 million and $68.9 million at December 31, 2008 and 2007, respectively. The long-term retainage which was included
in deferred charges and other assets - other was $19.2 million and $11.4 million at December 31, 2008 and 2007, respectively.
Derivative instruments
The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. The Company's policy prohibits the use of derivative instruments for speculating to take advantage of market trends and conditions, and the Company has procedures in place to monitor compliance with its policies. The Company is exposed to credit-related losses in relation to derivative instruments in the event of nonperformance by counterparties.
The Company's policy generally allows the hedging of monthly forecasted natural gas and oil production at Fidelity for a period up to 24 months from the time the Company enters into the hedge. The Company's policy requires that interest rate derivative instruments not exceed a period of 24 months and foreign currency derivative instruments not exceed a 12-month period. The Company's policy allows the hedging of monthly forecasted purchases of natural gas at Cascade and Intermountain for a period up to three years.
The Company’s policy requires that each month as physical natural gas and oil production at Fidelity occurs and the commodity is sold, the related portion of the derivative agreement for that month’s production must settle with its counterparties. Settlements represent the exchange of cash between the Company and its counterparties based on the notional quantities and prices for each month’s physical delivery as specified within the agreements. The fair value of the remaining notional amounts on the derivative agreements is recorded on the balance sheet as an asset or liability measured at fair value with the unrealized gains or losses recognized as a component of accumulated other comprehensive income (loss). The Company's policy also requires settlement of natural gas derivative instruments at Cascade and Intermountain monthly and all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and any foreign currency derivative transaction settlement periods may not exceed a 12-month period. The Company has policies and procedures that management believes minimize credit-risk exposure. Accordingly, the Company does not anticipate any material effect on its financial position or results of operations as a result of nonperformance by counterparties. For more information on derivative instruments, see Note 7.
The estimated fair values of the Company's swap and collar agreements reflect the estimated amounts the Company would receive or pay to terminate the contracts at the reporting date. These values are based upon, among other things, futures prices, volatility and time to maturity.
Asset retirement obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, the Company either settles the obligation for the recorded amount or incurs a gain or loss at its nonregulated operations or incurs a regulatory asset or liability at its regulated operations. For more information on asset retirement obligations, see Note 11.
Natural gas costs recoverable or refundable through rate adjustments
Under the terms of certain orders of the applicable state public service commissions, the Company is deferring natural gas commodity, transportation and storage costs that are greater or less than amounts presently being recovered through its existing rate schedules. Such orders generally provide that these amounts are recoverable or refundable through rate adjustments within a period ranging from 12 to 28 months from the time such costs are paid. Natural gas costs refundable through rate adjustments were $64,000 and $11.6 million at December 31, 2008 and 2007, respectively, which is included in other accrued liabilities. Natural gas costs recoverable through rate adjustments were $51.7 million and $3.9 million at December 31, 2008 and 2007, respectively, which is included in prepayments and other current assets.
Insurance
Certain subsidiaries of the Company are insured for workers' compensation losses, subject to deductibles ranging up to $750,000 per occurrence. Automobile liability and general liability losses are insured, subject to deductibles ranging up to $500,000 per accident or occurrence. These subsidiaries have excess coverage above the primary automobile and general liability policies on a claims first-made basis beyond the deductible levels. The subsidiaries of the Company are retaining losses up to the deductible amounts accrued on the basis of estimates of liability for claims incurred and for claims incurred but not reported.
Income taxes
The Company provides deferred federal and state income taxes on all temporary differences between the book and tax basis of the Company's assets and liabilities. Excess deferred income tax balances associated with the Company's rate-regulated activities resulting from the Company's adoption of SFAS No. 109 have been recorded as a regulatory liability and are included in other liabilities. These regulatory liabilities are expected to be reflected as a reduction in future rates charged to customers in accordance with applicable regulatory procedures.
The Company uses the deferral method of accounting for investment tax credits and amortizes the credits on electric and natural gas distribution plant over various periods that conform to the ratemaking treatment prescribed by the applicable state public service commissions.
The Company accounts for uncertain tax positions in accordance with FIN 48. FIN 48 establishes standards for measurement and recognition in financial statements of tax positions taken or expected to be taken in an income tax return. Under FIN 48, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income taxes.
Foreign currency translation adjustment
The functional currency of the Company's investment in the Brazilian Transmission Lines, as further discussed in Note 4, is the Brazilian Real. Translation from the Brazilian Real to the U.S. dollar for assets and liabilities is performed using the exchange rate in effect at the balance sheet date. Revenues and expenses are translated on a year-to-date basis using weighted average daily exchange rates. Adjustments resulting from such translations are reported as a separate component of other comprehensive income (loss) in common stockholders' equity.
Transaction gains and losses resulting from the effect of exchange rate changes on transactions denominated in a currency other than the functional currency of the reporting entity would be recorded in income.
Common stock split
On May 11, 2006, the Company's Board of Directors approved a three-for-two common stock split. For more information on the common stock split, see Note 13.
Earnings per common share
Basic earnings per common share were computed by dividing earnings on common stock by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the year, plus the effect of outstanding stock options, restricted stock grants and performance share awards. In 2008, 2007 and 2006, there were no shares excluded from the calculation of diluted earnings per share. Common stock outstanding includes issued shares less shares held in treasury.
Stock-based compensation
On January 1, 2006, the Company adopted SFAS No. 123 (revised). This accounting standard requires entities to recognize compensation expense in an amount equal to the grant-date fair value of share-based payments granted to employees. SFAS No. 123 (revised) was adopted using the modified prospective method, recognizing compensation expense for all awards granted after the date of adoption of the standard and for the unvested portion of previously granted awards that remain outstanding at the date of adoption.
For more information on the Company's stock-based compensation, see Note 14.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as impairment testing of long-lived assets, goodwill and natural gas and oil properties; fair values of acquired assets and liabilities under the purchase method of accounting; natural gas and oil reserves; aggregate reserves; property depreciable lives; tax provisions; uncollectible accounts; environmental and other loss contingencies; accumulated provision for revenues subject to refund; costs on construction contracts; unbilled revenues; actuarially determined benefit costs; asset retirement obligations; the valuation of stock-based compensation; and the fair value of derivative instruments. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Cash flow information
Cash expenditures for interest and income taxes were as follows:
Income taxes paid for the year ended December 31, 2007, were higher than the amount paid for the years ended December 31, 2008 and 2006, primarily due to higher estimated quarterly tax
payments paid in 2007 due in large part to the gain on the sale of the domestic independent power production assets as discussed in Note 3.
New accounting standards
SFAS No. 157 In September 2006, the FASB issued SFAS No. 157. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The standard applies under other accounting pronouncements that require or permit fair value measurements with certain exceptions. SFAS No. 157 was effective for the Company on January 1, 2008. FSP FAS No. 157-2 delays the effective date of SFAS No. 157 for certain nonfinancial assets and nonfinancial liabilities to January 1, 2009. The types of assets and liabilities that are recognized at fair value for which the Company has not applied the provisions of SFAS No. 157, due to the delayed effective date, include nonfinancial assets and nonfinancial liabilities initially measured at fair value in a business combination or new basis event, certain fair value measurements associated with goodwill impairment testing, indefinite-lived intangible assets and nonfinancial long-lived assets measured at fair value for impairment assessment, and asset retirement obligations initially measured at fair value. The adoption of SFAS No. 157, including the application to certain nonfinancial assets and nonfinancial liabilities with a delayed effective date of January 1, 2009, did not have a material effect on the Company's financial position or results of operations.
SFAS No. 159 In February 2007, the FASB issued SFAS No. 159. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 was effective for the Company on January 1, 2008, and at adoption, the Company elected to measure its investments in certain fixed-income and equity securities at fair value in accordance with SFAS No. 159. These investments prior to January 1, 2008, were accounted for as available-for-sale investments and recorded at fair value with any unrealized gains or losses, net of income taxes, recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets until realized. Upon the adoption of SFAS No. 159, the unrealized gain on the available-for-sale investments of $405,000 (after tax) was recorded as an increase to the January 1, 2008, balance of retained earnings. The adoption of SFAS No. 159 did not have a material effect on the Company's financial position or results of operations.
SFAS No. 141 (revised) In December 2007, the FASB issued SFAS No. 141 (revised). SFAS No. 141 (revised) requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any noncontrolling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exception. In addition, SFAS No. 141 (revised) requires that acquisition-related costs will be generally expensed as incurred. SFAS No. 141 (revised) also expands the disclosure requirements for business combinations. SFAS No. 141 (revised) was effective for the Company on January 1, 2009. The adoption of SFAS No. 141 (revised) did not have a material effect on the Company’s financial position or results of operations.
SFAS No. 160 In December 2007, the FASB issued SFAS No. 160. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 was effective for the Company on January 1, 2009. The adoption of SFAS No. 160 did not have a material effect on the Company’s financial position or results of operations.
SFAS No. 161 In March 2008, the FASB issued SFAS No. 161. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This Statement was effective for the Company on January 1, 2009. The adoption of SFAS No. 161 will require additional disclosures regarding the Company's derivative instruments; however, it will not impact the Company's financial position or results of operations.
FSP FAS No. 132(R)-1 In December 2008, the FASB issued FSP FAS No. 132(R)-1. FSP FAS No. 132(R)-1 provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan to provide users of financial statements with an understanding of how investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period and significant concentrations of risk within plan assets. This statement was effective for the Company on January 1, 2009. The adoption of FSP FAS No. 132(R)-1 will require additional disclosures regarding the Company's defined benefit pension and other postretirement plans; however, it will not impact the Company's financial position or results of operations.
Modernization of Oil and Gas Reporting In January 2009, the SEC adopted final rules amending its oil and gas reporting requirements. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. The final rules are effective for the Company on December 31, 2009.
Comprehensive income
Comprehensive income is the sum of net income as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, pension liability adjustments, foreign currency translation adjustments and gains on available-for-sale investments. For more information on derivative instruments, see Note 7.
The components of other comprehensive income (loss), and their related tax effects for the years ended December 31, 2008, 2007 and 2006, were as follows:
The after-tax components of accumulated other comprehensive income (loss) as of December 31, 2008, 2007 and 2006, were as follows:
NOTE 2 - ACQUISITIONS
In 2008, the Company acquired a construction services business in Nevada; natural gas properties in Texas; construction materials and contracting businesses in Alaska, California, Idaho and Texas; and Intermountain, a natural gas distribution business, as discussed below. The total purchase consideration for these businesses and properties and purchase price adjustments with respect to certain other acquisitions made prior to 2008, consisting of the Company’s common stock and cash and the outstanding indebtedness of Intermountain, was $624.5 million.
On October 1, 2008, the acquisition of Intermountain was finalized and Intermountain became an indirect wholly owned subsidiary of the Company. Intermountain’s service area is in Idaho.
In 2007, the Company acquired construction materials and contracting businesses in North Dakota, Texas and Wyoming; a construction services business in Nevada; and Cascade, a natural gas distribution business, as discussed below. The total purchase consideration for these businesses and properties and purchase price adjustments with respect to certain other acquisitions made prior to 2007, consisting of the Company's common stock and cash and the outstanding indebtedness of Cascade, was $526.3 million.
On July 2, 2007, the acquisition of Cascade was finalized and Cascade became an indirect wholly owned subsidiary of the Company. Cascade's natural gas service areas are in Washington and Oregon.
In 2006, the Company acquired a construction services business in Nevada, natural gas and oil production properties in Wyoming, and construction materials and contracting businesses in California and Washington, none of which was material. The total purchase consideration for these businesses and properties and purchase price adjustments with respect to certain other acquisitions made prior to 2006, consisting of the Company's common stock and cash, was $120.6 million.
The above acquisitions were accounted for under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed have been preliminarily recorded at their respective fair values as of the date of acquisition. On certain of the above acquisitions made in 2008, final fair market values are pending the completion of the review of the relevant assets and liabilities as of the acquisition date. The results of operations of the acquired businesses and properties are included in the financial statements since the date of each acquisition. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented, as such acquisitions were not material to the Company's financial position or results of operations.
NOTE 3 - DISCONTINUED OPERATIONS
Innovatum, a component of the pipeline and energy services segment, specialized in cable and pipeline magnetization and location. During the third quarter of 2006, the Company initiated a plan to sell Innovatum because the Company determined that Innovatum is a non-strategic asset. During the fourth quarter of 2006, the stock and a portion of the assets of Innovatum were sold and the Company sold the remaining assets of Innovatum on January 23, 2008. The loss on disposal of Innovatum was not material.
During the fourth quarter of 2006, the Company initiated a plan to sell certain of the domestic assets of Centennial Resources. The plan to sell was based on the increased market demand for independent power production assets, combined with the Company's desire to efficiently fund future capital needs. The Company subsequently committed to a plan to sell CEM due to strong interest in the operations of CEM during the bidding process for the domestic independent power production assets in the first quarter of 2007.
On July 10, 2007, Centennial Resources sold its domestic independent power production business consisting of Centennial Power and CEM to Bicent Power LLC (formerly known as Montana Acquisition Company LLC). The transaction was valued at $636 million, which included the assumption of approximately $36 million of project-related debt. The gain on the sale of the assets, excluding the gain on the sale of Hartwell as discussed in Note 4, was approximately $85.4 million (after tax).
In accordance with SFAS No. 144, the Company's consolidated financial statements and accompanying notes for prior periods present the results of operations of Innovatum and the domestic independent power production assets as discontinued operations. In addition, the assets and liabilities of these operations were treated as held for sale, and as a result, no depreciation, depletion and amortization expense was recorded from the time each of the assets was classified as held for sale.
In accordance with SFAS No. 142, at the time the Company committed to the plan to sell each of the assets, the Company was required to test the respective assets for goodwill impairment. The fair value of Innovatum, a reporting unit for goodwill impairment testing, was estimated using the expected proceeds from the sale, which was estimated to be the current book value of the assets of Innovatum other than its goodwill. As a result, a goodwill impairment of $4.3 million (before tax) was recognized and recorded as part of discontinued operations, net of tax, in the Consolidated Statements of Income in the third quarter of 2006. There were no goodwill impairments associated with the other assets held for sale.
Operating results related to Innovatum for the years ended December 31, 2007 and 2006, were as follows:
The income tax benefit for the year ended December 31, 2006, is larger than the customary relationship between the income tax benefit and the loss before tax due to a capital loss tax benefit (which reflects the effect of the $4.3 million and $4.0 million goodwill impairments in 2006 and 2004, respectively) resulting from the sale of the Innovatum stock.
Operating results related to the domestic independent power production assets for the years ended December 31, 2007 and 2006, were as follows:
The income tax benefit for the year ended December 31, 2006, reflects a renewable electricity production tax credit of $4.4 million.
Revenues at the former independent power production operations were recognized based on electricity delivered and capacity provided, pursuant to contractual commitments and, where applicable, revenues were recognized under EITF No. 91-6 ratably over the terms of the related contract. Arrangements with multiple revenue-generating activities were recognized under EITF No. 00-21 with the multiple deliverables divided into separate units of accounting based on
specific criteria and revenues of the arrangements allocated to the separate units based on their relative fair values.
The carrying amounts of the assets and liabilities related to discontinued operations at December 31, 2007, were not material.
NOTE 4 - EQUITY METHOD INVESTMENTS
Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. The Company's equity method investments at December 31, 2008 and 2007, include the Brazilian Transmission Lines.
In August 2006, MDU Brasil acquired ownership interests in companies owning the Brazilian Transmission Lines. The interests involve the ENTE (13.3-percent ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership interest) electric transmission lines, which are primarily in northeastern and southern Brazil. The transmission contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments and have between 22 and 24 years remaining under the contracts. Alusa, Brascan and CEMIG hold the remaining ownership interests, with CELESC also having an ownership interest in ECTE. The functional currency for the Brazilian Transmission Lines is the Brazilian Real.
In September 2004, Centennial Resources, through indirect wholly owned subsidiaries, acquired a 50-percent ownership interest in Hartwell, which owns a 310-MW natural gas-fired electric generating facility near Hartwell, Georgia. In July 2007, the Company sold its ownership interest in Hartwell, and realized a gain of $10.1 million ($6.1 million after tax) from the sale which is recorded in earnings from equity method investments on the Consolidated Statements of Income.
At December 31, 2008 and 2007, the Company's equity method investments had total assets of $294.7 million and $398.4 million, respectively, and long-term debt of $158.0 million and $211.2 million, respectively. The Company's investment in its equity method investments was approximately $44.4 million and $59.0 million, including undistributed earnings of $6.8 million and $6.9 million, at December 31, 2008 and 2007, respectively.
NOTE 5 - GOODWILL AND OTHER INTANGIBLE ASSETS
The changes in the carrying amount of goodwill for the year ended December 31, 2008, were as follows:
The changes in the carrying amount of goodwill for the year ended December 31, 2007, were as follows:
Other amortizable intangible assets at December 31, 2008 and 2007, were as follows:
Amortization expense for intangible assets for the years ended December 31, 2008, 2007 and 2006, was $5.1 million, $4.4 million and $4.3 million, respectively. Estimated amortization expense for intangible assets is $5.1 million in 2009, $3.7 million in 2010, $3.1 million in 2011, $3.0 million in 2012, $2.5 million in 2013 and $11.0 million thereafter.
NOTE 6 - REGULATORY ASSETS AND LIABILITIES
The following table summarizes the individual components of unamortized regulatory assets and liabilities as of December 31:
The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates.
If, for any reason, the Company's regulated businesses cease to meet the criteria for application of SFAS No. 71 for all or part of their operations, the regulatory assets and liabilities relating to those portions ceasing to meet such criteria would be removed from the balance sheet and included in the statement of income as an extraordinary item in the period in which the discontinuance of SFAS No. 71 occurs.
NOTE 7 - DERIVATIVE INSTRUMENTS
Derivative instruments, including certain derivative instruments embedded in other contracts, are required to be recorded on the balance sheet as either an asset or liability measured at fair value. Changes in the derivative instrument's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Accounting for qualifying hedges allows derivative gains and losses to offset the related results on the hedged item in the income statement and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.
In the event a derivative instrument being accounted for as a cash flow hedge does not qualify for hedge accounting because it is no longer highly effective in offsetting changes in cash flows of a hedged item; if the derivative instrument expires or is sold, terminated or exercised; or if management determines that designation of the derivative instrument as a hedge instrument is no longer appropriate, hedge accounting would be discontinued and the derivative instrument would continue to be carried at fair value with changes in its fair value recognized in earnings. In these circumstances, the net gain or loss at the time of discontinuance of hedge accounting would remain in accumulated other comprehensive income (loss) until the period or periods during which the hedged forecasted transaction affects earnings, at which time the net gain or loss would be reclassified into earnings. In the event a cash flow hedge is discontinued because it is unlikely that a forecasted transaction will occur, the derivative instrument would continue to be carried on the balance sheet at its fair value, and gains and losses that had accumulated in other comprehensive income (loss) would be recognized immediately in earnings. In the event of a sale, termination or extinguishment of a foreign currency derivative, the resulting gain or loss would be recognized immediately in earnings. The Company's policy requires approval to terminate a derivative instrument prior to its original maturity. As of December 31, 2008, the Company had no outstanding foreign currency or interest rate hedges.
Cascade and Intermountain
At December 31, 2008, Cascade and Intermountain held natural gas swap agreements which were not designated as hedges. Cascade and Intermountain utilize natural gas swap agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas on their forecasted purchases of natural gas for core customers in accordance with authority granted by the IPUC, WUTC and OPUC. Core customers consist of residential, commercial and smaller industrial customers. The fair value of the derivative instrument must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability. Cascade and Intermountain apply SFAS No. 71 and record periodic changes in the fair market value of the derivative instruments on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and settlements of these arrangements are expected to be recovered through the purchased gas cost adjustment mechanism. Under the terms of these arrangements, Cascade and Intermountain will either pay or receive settlement payments based on the difference between the fixed strike price and the monthly index price applicable to each contract. At December 31, 2008, the fair value of Cascade’s natural gas swap agreements is presented net of the collateral provided to the counterparty of $11.1 million.
Fidelity
At December 31, 2008, Fidelity held natural gas swaps, a basis swap and collar agreements designated as cash flow hedging instruments. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas on its forecasted sales of natural gas production. These derivatives were designated as cash flow hedges of the forecasted sales of the related production.
The fair value of the hedging instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability. Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). At the date the natural gas quantities are settled, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. The proceeds received for natural gas production are generally based on market prices.
For the years ended December 31, 2008, 2007 and 2006, the amount of hedge ineffectiveness was immaterial, and there were no components of the derivative instruments' gain or loss excluded from the assessment of hedge effectiveness. Gains and losses must be reclassified into earnings as a result of the discontinuance of cash flow hedges if it is probable that the original forecasted transactions will not occur. There were no such reclassifications into earnings as a result of the discontinuance of hedges.
Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in the line item in which the hedged item is recorded. As of December 31, 2008, the maximum term of the swap and collar agreements, in which the exposure to the variability in future cash flows for forecasted transactions is being hedged, is 36 months. The Company estimates that over the next 12 months, net gains of approximately $47.6 million (after tax) will be reclassified from accumulated other comprehensive income into earnings, subject to changes in natural gas market prices, as the hedged transactions affect earnings.
NOTE 8 - FAIR VALUE MEASUREMENTS
On January 1, 2008, the Company adopted SFAS No. 157 and SFAS No. 159, as discussed in Note 1.
Upon the adoption of SFAS No. 159, the Company elected to measure its investments in certain fixed-income and equity securities at fair value. These investments had previously been accounted for as available-for-sale investments in accordance with SFAS No. 115. The Company anticipates using these investments to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $27.7 million as of December 31, 2008, are classified as Investments on the Consolidated Balance Sheets. The decrease in the fair value of these investments for the year ended December 31, 2008, was $8.6 million (before tax), which is considered part of the cost of the plan, and is classified in operation and maintenance expense on the Consolidated Statements of Income. The Company did not elect the fair value option for its remaining available-for-sale securities, which are auction rate securities. The Company’s auction rate securities, which totaled $11.4 million at December 31, 2008, are accounted for as available-for-sale in accordance with SFAS No. 115 and are recorded at fair value. The fair value of the auction rate securities approximate cost and, as a result, there are no accumulated unrealized gains or losses recorded in
accumulated other comprehensive income (loss) on the Consolidated Balance Sheets related to these investments.
SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The Company’s assets and liabilities measured at fair value on a recurring basis are as follows:
The estimated fair value of the Company’s Level 1 available-for-sale securities is based on quoted market prices in active markets for identical equity and fixed-income securities. The estimated fair value of the Company’s Level 2 available-for-sale securities is based on comparable market transactions. The estimated fair values of the Company’s commodity derivative instruments reflects the estimated amounts the Company would receive or pay to terminate the contracts at the reporting date. These values are based upon, among other things, futures prices, volatility and time to maturity.
The Company’s long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The estimated fair value of the Company’s long-term debt was based on quoted market prices of the same or similar issues.
The estimated fair value of the Company's long-term debt at December 31 was as follows:
The estimated fair value of the Company’s commodity derivative instruments at December 31 was as follows:
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.
NOTE 9 - SHORT-TERM BORROWINGS
MDU Resources Group, Inc. In connection with the funding of the Intermountain acquisition, on September 26, 2008, the Company entered into a term loan agreement providing for a commitment amount of $175 million. On October 1, 2008, the Company borrowed $170 million under this agreement, which expires on March 24, 2009. There was $57.0 million outstanding under the term loan agreement at December 31, 2008.
The agreement contains customary covenants and default provisions, including covenants of the Company not to permit, as of the end of any fiscal quarter, (A) the ratio of funded debt to total capitalization (on a consolidated basis) to be greater than 65 percent or (B) the ratio of funded debt to capitalization (determined with respect to the Company only, excluding subsidiaries) to be greater than 65 percent. The agreement also includes a covenant that does not permit the ratio of the Company’s earnings before interest, taxes, depreciation and amortization to interest expense (determined with respect to the Company only, excluding subsidiaries), for the 12-month period ended each fiscal quarter, to be less than 2.5 to 1. The Company was in compliance with these covenants and met the required conditions at December 31, 2008.
There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries.
Cascade Natural Gas Corporation Cascade has a revolving credit agreement with various banks totaling $50 million with certain provisions allowing for increased borrowings, up to a maximum of $75 million. The $50 million credit agreement expires on December 28, 2012, with provisions allowing for an extension of up to two years upon consent of the banks. Cascade also has a revolving credit agreement totaling $15 million, which expires on March 11, 2009. Under the terms of the $50 million credit agreement, $48.1 million and $1.7 million were outstanding at December 31, 2008 and 2007, respectively. There was no amount outstanding under the $15 million credit agreement at December 31, 2008. These borrowings are classified as short-term borrowings as Cascade intends to repay the borrowings within one year. The weighted average
interest rate for borrowings outstanding at December 31, 2008, was less than one percent. As of December 31, 2008, there were outstanding letters of credit, as discussed in Note 20, of which $1.9 million reduced amounts available under the $50 million credit agreement.
In order to borrow under Cascade's credit agreements, Cascade must be in compliance with the applicable covenants and certain other conditions. This includes a covenant not to permit, at any time, the ratio of total debt to total capitalization to be greater than 65 percent. Cascade was in compliance with these covenants and met the required conditions at December 31, 2008.
Cascade's credit agreements contain cross-default provisions. These provisions state that if Cascade fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the agreement will be in default. Certain of Cascade's financing agreements and Cascade's practices limit the amount of subsidiary indebtedness.
NOTE 10 - LONG-TERM DEBT AND INDENTURE PROVISIONS
Long-term debt outstanding at December 31 was as follows:
The amounts of scheduled long-term debt maturities for the five years and thereafter following December 31, 2008, aggregate $78.7 million in 2009; $49.1 million in 2010; $94.8 million in 2011; $290.7 million in 2012; $258.8 million in 2013 and $875.2 million thereafter.
Certain debt instruments of the Company and its subsidiaries, including those discussed below, contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2008.
MDU Resources Group, Inc. The Company has a revolving credit agreement with various banks totaling $125 million (with provision for an increase, at the option of the Company on stated conditions, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement at December 31, 2008 and 2007. The credit agreement supports the Company’s $125 million commercial paper program. Although volatility in the capital markets has recently increased significantly, the Company continues to issue commercial paper to meet its current needs. Under the Company’s commercial paper program, $22.5 million and $61.0 million was outstanding at December 31, 2008 and 2007, respectively. The commercial paper borrowings are classified as long-term debt as they are intended to be refinanced on a long-term basis through continued commercial paper borrowings (supported by the credit agreement, which expires on June 21, 2011).
In order to borrow under the Company's credit agreement, the Company must be in compliance with the applicable covenants and certain other conditions, including covenants not to permit, as of the end of any fiscal quarter, (A) the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent or (B) the ratio of funded debt to capitalization (determined with respect to the Company alone, excluding its subsidiaries) to be greater than 65 percent. Also included is a covenant that does not permit the ratio of the Company's earnings before interest, taxes, depreciation and amortization to interest expense (determined with respect to the Company alone, excluding its subsidiaries), for the 12-month period ended each fiscal quarter, to be less than 2.5 to 1. Other covenants include restrictions on the sale of certain assets and on the making of certain investments. The Company was in compliance with these covenants and met the required conditions at December 31, 2008. In the event the Company does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.
There are no credit facilities that contain cross-default provisions between the Company and any of its subsidiaries.
The Company's issuance of first mortgage debt is subject to certain restrictions imposed under the terms and conditions of its Mortgage. Generally, those restrictions require the Company to fund $1.43 of unfunded property or use $1.00 of refunded bonds for each dollar of indebtedness incurred under the Mortgage and, in some cases, to certify to the trustee that annual earnings (pretax and before interest charges), as defined in the Mortgage, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the tests, as of December 31, 2008, the Company could have issued approximately $620 million of additional first mortgage bonds.
Approximately $618.8 million in net book value of the Company’s electric and natural gas distribution properties at December 31, 2008, with certain exceptions, are subject to the lien of the Mortgage and to the junior lien of the Indenture.
MDU Energy Capital, LLC On October 1, 2008, MDU Energy Capital entered into an amendment to its master shelf agreement which increased the facility amount from $125 million to $175 million. Under the terms of the master shelf agreement, $165.0 million and $85.0 million was outstanding at December 31, 2008 and 2007, respectively. MDU Energy Capital may incur additional indebtedness under the master shelf agreement until the earlier of August 14, 2010, or such time as the agreement is terminated by either of the parties thereto.
On October 1, 2008, MDU Energy Capital borrowed $80.0 million under the agreement. The indebtedness consists of $30 million of senior notes due October 1, 2013, and $50 million of
senior notes due October 1, 2015. MDU Energy Capital used the proceeds from the borrowing to pay a dividend to the Company which, in turn, used this dividend to partially fund the acquisition of Intermountain, as previously discussed.
The master shelf agreement contains customary covenants and provisions, including covenants of MDU Energy Capital not to permit (A) the ratio of its total debt (on a consolidated basis) to adjusted total capitalization to be greater than 70 percent, or (B) the ratio of subsidiary debt to subsidiary capitalization to be greater than 65 percent, or (C) the ratio of Intermountain’s total debt (determined on a consolidated basis) to total capitalization to be greater than 65 percent. The agreement also includes a covenant requiring the ratio of MDU Energy Capital earnings before interest and taxes to interest expense (on a consolidated basis), for the 12-month period ended each fiscal quarter to be greater than 1.5 to 1. MDU Energy Capital was in compliance with these covenants and met the required conditions at December 31, 2008. In addition, payment obligations under the master shelf agreement may be accelerated upon the occurrence of an event of default (as described in the agreement).
Intermountain Gas Company Intermountain has a revolving credit agreement with various banks totaling $65 million with certain provisions allowing for increased borrowings, up to a maximum of $70 million. The credit agreement expires on August 31, 2010. Under the terms of the credit agreement, $36.5 million was outstanding at December 31, 2008.
In order to borrow under Intermountain's credit agreement, Intermountain must be in compliance with the applicable covenants and certain other conditions, including covenants not to permit, as of the end of any fiscal quarter, (A) the ratio of funded debt to total capitalization (determined on a consolidated basis) to be greater than 65 percent, or (B) the ratio of Intermountain’s earnings before interest, taxes, depreciation and amortization to interest expense (determined on a consolidated basis), for the 12-month period ended each fiscal quarter, to be less than 2 to 1. Other covenants include limitations on the sale of certain assets and on the making of certain loans and investments. Intermountain was in compliance with these covenants and met the required conditions at December 31, 2008. In the event Intermountain does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.
Intermountain's credit agreement contains cross-default provisions. These provisions state that if (i) Intermountain fails to make any payment with respect to any indebtedness or guarantee in excess of $5 million, (ii) any other event occurs that would permit the holders of indebtedness or the beneficiaries of guarantees to become payable, or (iii) certain conditions result in an early termination date under any swap contract, then Intermountain shall be in default under the revolving credit agreement.
Centennial Energy Holdings, Inc. Centennial has a revolving credit agreement with various banks and institutions totaling $400 million with certain provisions allowing for increased borrowings. The credit agreement supports Centennial’s $400 million commercial paper program. Although volatility in the capital markets has recently increased significantly, the Company continues to issue commercial paper to meet its current needs. There were no outstanding borrowings under the Centennial credit agreement at December 31, 2008 and 2007. Under the Centennial commercial paper program, $150.0 million was outstanding at December 31, 2008, and there was no amount outstanding at December 31, 2007. The Centennial commercial paper borrowings are classified as long-term debt as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings (supported by the Centennial credit agreement). The revolving credit agreement includes a provision for an increase, at the option of Centennial on stated conditions, up to a maximum of $450 million and expires on
December 13, 2012. As of December 31, 2008, Centennial had letters of credit outstanding, as discussed in Note 20, of which $24.3 million reduced amounts available under the agreement.
Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $550 million. Under the terms of the master shelf agreement, $509.0 million and $418.5 million was outstanding at December 31, 2008 and 2007, respectively. The ability to request additional borrowings under this master shelf agreement expires on May 8, 2009.
In order to borrow under Centennial’s credit agreement and the Centennial uncommitted long-term master shelf agreement, Centennial and certain of its subsidiaries must be in compliance with the applicable covenants and certain other conditions, including covenants not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 65 percent (for the $400 million credit agreement) and 60 percent (for the master shelf agreement). The master shelf agreement also includes a covenant that does not permit the ratio of Centennial's earnings before interest, taxes, depreciation and amortization to interest expense, for the 12-month period ended each fiscal quarter, to be less than 1.75 to 1. Other covenants include minimum consolidated net worth, limitation on priority debt and restrictions on the sale of certain assets and on the making of certain loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at December 31, 2008. In the event Centennial or such subsidiaries do not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.
Certain of Centennial’s financing agreements contain cross-default provisions. These provisions state that if Centennial or any subsidiary of Centennial fails to make any payment with respect to any indebtedness or contingent obligation, in excess of a specified amount, under any agreement that causes such indebtedness to be due prior to its stated maturity or the contingent obligation to become payable, the applicable agreements will be in default. Certain of Centennial’s financing agreements and Centennial’s practices limit the amount of subsidiary indebtedness.
Williston Basin Interstate Pipeline Company In December 2008, Williston Basin entered into an uncommitted long-term private shelf agreement that allows for borrowings up to $125 million. Under the terms of the private shelf agreement, $72.5 million was outstanding at December 31, 2008. The $72.5 million outstanding consists of $20.0 million of notes issued under the private shelf agreement and $52.5 million of notes issued under a master shelf agreement that expired on December 20, 2008. At December 31, 2007, $80.0 million was outstanding under the prior agreement. The ability to request additional borrowings under this private shelf agreement expires on December 23, 2010, with certain provisions allowing for an extension to December 23, 2011.
In order to borrow under its uncommitted long-term private shelf agreement, Williston Basin must be in compliance with the applicable covenants and certain other conditions, including covenants not to permit, as of the end of any fiscal quarter, the ratio of total debt to total capitalization to be greater than 55 percent. Other covenants include limitation on priority debt and some restrictions on the sale of certain assets and the making of certain investments. Williston Basin was in compliance with these covenants and met the required conditions at December 31, 2008. In the event Williston Basin does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.
NOTE 11 - ASSET RETIREMENT OBLIGATIONS
The Company records obligations related to the plugging and abandonment of natural gas and oil wells, decommissioning of certain electric generating facilities and reclamation of certain aggregate properties.
A reconciliation of the Company's liability, which is included in other liabilities, for the years ended December 31 was as follows:
The Company believes that any expenses related to asset retirement obligations at the Company’s regulated operations will be recovered in rates over time and, accordingly, defers such expenses as regulatory assets.
The fair value of assets that are legally restricted for purposes of settling asset retirement obligations at December 31, 2008 and 2007, was $5.9 million and $5.8 million, respectively.
NOTE 12 - PREFERRED STOCKS
Preferred stocks at December 31 were as follows:
The 4.50% Series and 4.70% Series preferred stocks outstanding are subject to redemption, in whole or in part, at the option of the Company with certain limitations on 30 days notice on any quarterly dividend date at a redemption price, plus accrued dividends, of $105 per share and $102 per share, respectively.
In the event of a voluntary or involuntary liquidation, all preferred stock series holders are entitled to $100 per share, plus accrued dividends.
The affirmative vote of two-thirds of a series of the Company's outstanding preferred stock is necessary for amendments to the Company's charter or bylaws that adversely affect that series; creation of or increase in the amount of authorized stock ranking senior to that series (or an
affirmative majority vote where the authorization relates to a new class of stock that ranks on parity with such series); a voluntary liquidation or sale of substantially all of the Company's assets; a merger or consolidation, with certain exceptions; or the partial retirement of that series of preferred stock when all dividends on that series of preferred stock have not been paid. The consent of the holders of a particular series is not required for such corporate actions if the equivalent vote of all outstanding series of preferred stock voting together has consented to the given action and no particular series is affected differently than any other series.
Subject to the foregoing, the holders of common stock exclusively possess all voting power. However, if cumulative dividends on preferred stock are in arrears, in whole or in part, for one year, the holders of preferred stock would obtain the right to one vote per share until all dividends in arrears have been paid and current dividends have been declared and set aside.
NOTE 13 - COMMON STOCK
On May 11, 2006, the Company's Board of Directors approved a three-for-two common stock split to be effected in the form of a 50 percent common stock dividend. The additional shares of common stock were distributed on July 26, 2006, to common stockholders of record on July 12, 2006. Certain common stock information appearing in the accompanying consolidated financial statements has been restated in accordance with accounting principles generally accepted in the United States of America to give retroactive effect to the stock split.
In 1998, the Company's Board of Directors declared, pursuant to a stockholders' rights plan, a dividend of one preference share purchase right for each outstanding share of the Company's common stock. The rights expired on December 31, 2008.
The Stock Purchase Plan provides interested investors the opportunity to make optional cash investments and to reinvest all or a percentage of their cash dividends in shares of the Company's common stock. The K-Plan is partially funded with the Company's common stock. From July 2006 through March 2007 and October 1, 2008 through October 21, 2008, the Stock Purchase Plan and K-Plan, with respect to Company stock, were funded with shares of authorized but unissued common stock. From January 2006 through June 2006, April 2007 through September 30, 2008, and October 22, 2008 through December 2008, purchases of shares of common stock on the open market were used to fund the Stock Purchase Plan and K-Plan. At December 31, 2008, there were 20.2 million shares of common stock reserved for original issuance under the Stock Purchase Plan and K-Plan.
NOTE 14 - STOCK-BASED COMPENSATION
The Company has several stock-based compensation plans and is authorized to grant options, restricted stock and stock for up to 17.1 million shares of common stock and has granted options, restricted stock and stock of 7.3 million shares through December 31, 2008. The Company generally issues new shares of common stock to satisfy stock option exercises, restricted stock, stock and performance share awards.
Total stock-based compensation expense was $3.7 million, net of income taxes of $2.3 million in 2008; $4.7 million, net of income taxes of $3.1 million in 2007; and $3.5 million, net of income taxes of $2.2 million in 2006.
As of December 31, 2008, total remaining unrecognized compensation expense related to stock-based compensation was approximately $5.0 million (before income taxes) which will be amortized over a weighted average period of 1.7 years.
Stock options
The Company has stock option plans for directors, key employees and employees. The Company has not granted stock options since 2003. Options granted to key employees automatically vest after nine years, but the plan provides for accelerated vesting based on the attainment of certain performance goals or upon a change in control of the Company, and expire 10 years after the date of grant. Options granted to directors and employees vest at the date of grant and three years after the date of grant, respectively, and expire 10 years after the date of grant.
The fair value of each option outstanding was estimated on the date of grant using the Black-Scholes option-pricing model.
A summary of the status of the stock option plans at December 31, 2008, and changes during the year then ended was as follows:
Summarized information about stock options outstanding and exercisable as of December 31, 2008, was as follows:
The aggregate intrinsic value in the preceding table represents the total intrinsic value (before income taxes), based on the Company's stock price on December 31, 2008, which would have been received by the option holders had all option holders exercised their options as of that date.
The weighted average remaining contractual life of options exercisable was 2.2 years at December 31, 2008.
The Company received cash of $5.9 million, $10.2 million and $4.5 million from the exercise of stock options for the years ended December 31, 2008, 2007 and 2006, respectively. The aggregate intrinsic value of options exercised during the years ended December 31, 2008, 2007 and 2006, was $8.1 million, $11.2 million and $4.4 million, respectively.
Restricted stock awards
Prior to 2002, the Company granted restricted stock awards under a long-term incentive plan. The restricted stock awards granted vest at various times ranging from one year to nine years from the
date of issuance, but certain grants may vest early based upon the attainment of certain performance goals or upon a change in control of the Company. The grant-date fair value is the market price of the Company's stock on the grant date.
A summary of the status of the restricted stock awards for the year ended December 31, 2008, was as follows:
The fair value of restricted stock awards that vested during the year ended December 31, 2006, was $1.8 million.
Stock awards
Nonemployee directors may receive shares of common stock instead of cash in payment for directors' fees under the nonemployee director stock compensation plan. There were 45,675 shares with a fair value of $1.2 million, 48,228 shares with a fair value of $1.5 million and 50,627 shares with a fair value of $1.3 million issued under this plan during the years ended December 31, 2008, 2007 and 2006, respectively.
Performance share awards
Since 2003, key employees of the Company have been awarded performance share awards each year. Entitlement to performance shares is based on the Company's total shareholder return over designated performance periods as measured against a selected peer group.
Target grants of performance shares outstanding at December 31, 2008, were as follows:
Participants may earn from zero to 200 percent of the target grant of shares based on the Company's total shareholder return relative to that of the selected peer group. Compensation expense is based on the grant-date fair value. The grant-date fair value of performance share awards granted during the years ended December 31, 2008, 2007 and 2006, was $30.71, $23.55 and $25.22, per share, respectively. The grant-date fair value for the performance shares was determined by Monte Carlo simulation using a blended volatility term structure comprised of 50 percent historical volatility and 50 percent implied volatility and a risk-free interest rate term structure based on U.S. Treasury security rates in effect as of the grant date. In addition, the mean over all simulation paths of the discounted dividends expected to be earned in the performance period used in the valuation was $1.64, $1.25 and $1.37 per target share for the 2008, 2007 and 2006 awards, respectively. The fair value of performance share awards that vested during the years ended December 31, 2008, 2007 and 2006, was $8.5 million, $6.0 million and $2.2 million, respectively.
A summary of the status of the performance share awards for the year ended December 31, 2008, was as follows:
NOTE 15 - INCOME TAXES
The components of income before income taxes for each of the years ended December 31 were as follows:
Income tax expense for the years ended December 31 was as follows:
Components of deferred tax assets and deferred tax liabilities recognized at December 31 were as follows:
As of December 31, 2008 and 2007, no valuation allowance has been recorded associated with the above deferred tax assets.
The following table reconciles the change in the net deferred income tax liability from December 31, 2007, to December 31, 2008, to deferred income tax expense:
Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before taxes. The reasons for this difference were as follows:
Prior to the sale of the domestic independent power production assets on July 10, 2007, as discussed in Note 3, the Company considered earnings (including the gain from the sale of its foreign equity method investment in a natural gas-fired electric generating facility in Brazil in 2005) to be reinvested indefinitely outside of the United States and, accordingly, no U.S. deferred income taxes were recorded with respect to such earnings. Following the sale of these assets, the Company reconsidered its long-term plans for future development and expansion of its foreign investment and has determined that it has no immediate plans to explore or invest in additional foreign investments at this time. Therefore, in accordance with SFAS No. 109, in the third quarter of 2007, deferred income taxes were accrued with respect to the temporary differences which had not been previously recorded. The amount of cumulative undistributed earnings for which there are temporary differences is approximately $34 million at December 31, 2008. The amount of deferred tax liability, net of allowable foreign tax credits, associated with the undistributed earnings at December 31, 2008, was approximately $10.8 million, which was largely recognized in 2007. Future earnings will also be subject to additional U.S. taxes, net of allowable foreign tax credits.
On January 1, 2007, the Company adopted FIN 48. The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction, and various state, local and foreign jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years ending prior to 2004.
Upon the adoption of FIN 48, the Company recognized a decrease in the liability for unrecognized tax benefits, which was not material and was accounted for as an increase to the January 1, 2007,
balance of retained earnings. At the date of adoption, the amount of unrecognized tax benefits was $4.5 million, including interest.
A reconciliation of the unrecognized tax benefits (excluding interest) for the years ended December 31, was as follows:
Included in the balance of unrecognized tax benefits at December 31, 2008, were $540,000 of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2008, was $5.7 million, including approximately $614,000 for the payment of interest and penalties.
The Company does not anticipate the amount of unrecognized tax benefits to significantly increase or decrease within the next 12 months.
For the years ended December 31, 2008, 2007 and 2006, the Company recognized approximately $819,000, $680,000 and $7,100, respectively, in interest expense. Penalties were not material in 2008, 2007 and 2006. The Company recognized interest income of approximately $223,000, $480,000 and $1.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. The Company had accrued liabilities of approximately $1.4 million, $718,000 and $436,000 at December 31, 2008, 2007 and 2006, respectively, for the payment of interest.
NOTE 16 - BUSINESS SEGMENT DATA
The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The vast majority of the Company's operations are located within the United States. The Company also has investments in foreign countries, which largely consist of Centennial Resources’ equity method investment in the Brazilian Transmission Lines.
The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added products and services.
The construction services segment specializes in constructing and maintaining electric and communication lines, gas pipelines, fire protection systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment.
The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides energy-related management services.
The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico.
The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii.
The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company's subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies' general liability and automobile liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' equity method investment in the Brazilian Transmission Lines.
The information below follows the same accounting policies as described in the Summary of Significant Accounting Policies. Information on the Company's businesses as of December 31 and for the years then ended was as follows:
The pipeline and energy services segment recognized income from discontinued operations, net of tax, of $106,000 for the year ended December 31, 2007, and a loss from discontinued operations, net of tax, of $2.1 million for the year ended December 31, 2006. The Other category reflects income from discontinued operations, net of tax, of $109.2 million and $10.1 million for the years ended December 31, 2007 and 2006, respectively.
Excluding income (loss) from discontinued operations at pipeline and energy services, earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from construction services, natural gas and oil production, construction materials and contracting, and other are all from nonregulated operations.
Capital expenditures for 2008, 2007 and 2006 include noncash transactions, including the issuance of the Company's equity securities, in connection with acquisitions and the outstanding indebtedness related to the 2008 Intermountain acquisition and the 2007 Cascade acquisition. The noncash transactions were $97.6 million in 2008, $217.3 million in 2007 and immaterial in 2006.
NOTE 17 - EMPLOYEE BENEFIT PLANS
The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Effective January 1, 2006, the Company discontinued defined pension plan benefits to all nonunion and certain union employees hired after December 31, 2005. These employees that would have been eligible for defined pension plan benefits are eligible to receive additional defined contribution plan benefits. The Company uses a measurement date of December 31 for all of its pension and postretirement benefit plans.
Changes in benefit obligation and plan assets for the year ended December 31, 2008, and amounts recognized in the Consolidated Balance Sheets at December 31, 2008, were as follows:
Employer contributions and benefits paid in the above table include only those amounts contributed directly to, or paid directly from, plan assets. Accumulated other comprehensive (income) loss in the above table includes amounts related to regulated operations, which are recorded as regulatory assets (liabilities) and are expected to be reflected in rates charged to customers over time.
Unrecognized pension actuarial losses in excess of 10 percent of the greater of the projected benefit obligation or the market-related value of assets is amortized on a straight-line basis over the expected average remaining service lives of active participants. The market-related value of assets is determined using a five-year average of assets. Unrecognized postretirement net transition obligation is amortized over a 20-year period ending 2012.
The accumulated benefit obligation for the defined benefit pension plans reflected above was $312.1 million and $307.7 million at December 31, 2008 and 2007, respectively.
The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets at December 31, 2008 and 2007, were as follows:
Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans for the years ended December 31, 2008, 2007 and 2006, were as follows:
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 2009 are $3.9 million and $605,000, respectively. The estimated net loss, prior service credit and transition obligation for the other postretirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2009 are $1.1 million, $2.8 million and $2.1 million, respectively.
Weighted average assumptions used to determine benefit obligations at December 31 were as follows:
Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 were as follows:
The expected rate of return on plan assets is based on the targeted asset allocation of 70 percent equity securities and 30 percent fixed-income securities and the expected rate of return from these asset categories. The expected return on plan assets for other postretirement benefits reflects insurance-related investment costs.
Health care rate assumptions for the Company's other postretirement benefit plans as of December 31 were as follows:
The Company's other postretirement benefit plans include health care and life insurance benefits for certain employees. The plans underlying these benefits may require contributions by the employee depending on such employee's age and years of service at retirement or the date of retirement. The accounting for the health care plans anticipates future cost-sharing changes that are consistent with the Company's expressed intent to generally increase retiree contributions each year by the excess of the expected health care cost trend rate over 6 percent.
Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed health care cost trend rates would have had the following effects at December 31, 2008:
The Company's defined benefit pension plans' asset allocation at December 31, 2008 and 2007, and weighted average targeted asset allocations at December 31, 2008, were as follows:
The Company's pension assets are managed by 11 outside investment managers. The Company's other postretirement assets are managed by three outside investment managers. The Company's investment policy with respect to pension and other postretirement assets is to make investments solely in the interest of the participants and beneficiaries of the plans and for the exclusive purpose of providing benefits accrued and defraying the reasonable expenses of administration. The Company strives to maintain investment diversification to assist in minimizing the risk of large losses. The Company's policy guidelines allow for investment of funds in cash equivalents, fixed-income securities and equity securities. The guidelines prohibit investment in commodities and future contracts, equity private placement, employer securities, leveraged or derivative securities, options, direct real estate investments, precious metals, venture capital and limited partnerships. The guidelines also prohibit short selling and margin transactions. The Company's practice is to periodically review and rebalance asset categories based on its targeted asset allocation percentage policy. Pension assets are largely valued based on quoted prices in active markets.
The Company's other postretirement benefit plans' asset allocation at December 31, 2008 and 2007, and weighted average targeted asset allocation at December 31, 2008, were as follows:
The Company expects to contribute approximately $12.4 million to its defined benefit pension plans and approximately $3.3 million to its postretirement benefit plans in 2009.
The following benefit payments, which reflect future service, as appropriate, are expected to be paid:
The following Medicare Part D subsidies are expected: $700,000 in 2009; $700,000 in 2010; $800,000 in 2011; $800,000 in 2012; $800,000 in 2013; and $5.1 million during the years 2014 through 2018.
In addition to company-sponsored plans, certain employees are covered under multi-employer pension plans administered by a union. Amounts contributed to the multi-employer plans were $73.1 million, $51.5 million and $57.6 million in 2008, 2007 and 2006, respectively.
In addition to the qualified plan defined pension benefits reflected in the table at the beginning of this note, the Company also has unfunded, nonqualified benefit plans for executive officers and certain key management employees that generally provide for defined benefit payments at age 65 following the employee's retirement or to their beneficiaries upon death for a 15-year period. The Company had investments of $56.3 million at December 31, 2008, consisting of equity securities of $25.1 million, life insurance carried on plan participants (payable upon the employee's death) of $28.5 million, fixed-income securities of $2.6 million, and other investments of $100,000, which the Company anticipates using to satisfy obligations under these plans. The Company's net periodic benefit cost for these plans was $9.0 million, $7.6 million and $7.5 million in 2008, 2007 and 2006, respectively. The total projected benefit obligation for these plans was $87.2 million and $80.6 million at December 31, 2008 and 2007, respectively. The accumulated benefit obligation for these plans was $77.3 million and $69.3 million at December 31, 2008 and 2007,
respectively. A discount rate of 6.25 percent and 6.00 percent at December 31, 2008 and 2007, respectively, and a rate of compensation increase of 4.00 percent and 4.25 percent at December 31, 2008 and 2007, respectively, were used to determine benefit obligations. A discount rate of 6.00 percent and 5.75 percent at December 31, 2008 and 2007, respectively, and a rate of compensation increase of 4.25 percent at December 31, 2008 and 2007, were used to determine net periodic benefit cost.
The amount of benefit payments for the unfunded, nonqualified benefit plans, as appropriate, are expected to aggregate $3.9 million in 2009; $4.4 million in 2010; $4.8 million in 2011; $5.2 million in 2012; $5.7 million in 2013; and $34.8 million for the years 2014 through 2018.
The Company sponsors various defined contribution plans for eligible employees. Costs incurred by the Company under these plans were $23.8 million in 2008, $21.1 million in 2007 and $17.3 million in 2006. The costs incurred in each year reflect additional participants as a result of business acquisitions.
SFAS No. 158 became effective for the Company as of December 31, 2006. The adoption resulted in a negative transition effect on accumulated other comprehensive loss of $18.5 million.
NOTE 18 - JOINTLY OWNED FACILITIES
The consolidated financial statements include the Company's 22.7 percent and 25.0 percent ownership interests in the assets, liabilities and expenses of the Big Stone Station and the Coyote Station, respectively. Each owner of the Big Stone and Coyote stations is responsible for financing its investment in the jointly owned facilities.
The Company's share of the Big Stone Station and Coyote Station operating expenses was reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income.
At December 31, the Company's share of the cost of utility plant in service and related accumulated depreciation for the stations was as follows:
NOTE 19 - REGULATORY MATTERS AND REVENUES SUBJECT TO REFUND
On August 20, 2008, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $757,000 annually or approximately 4 percent above current rates. A hearing before the WYPSC is scheduled for April 7, 2009. An order is anticipated in the second quarter of 2009.
In November 2006, Montana-Dakota filed an application with the NDPSC requesting an advance determination of prudence of Montana-Dakota's ownership interest in Big Stone Station II.
Hearings on the application were held in June 2007. In September 2007, Montana-Dakota informed the NDPSC that certain of the other participants in the project had withdrawn and it was considering the impact of these withdrawals on the project and its options. Supplemental hearings before the NDPSC were held in late April 2008 regarding possible plant configuration changes as a result of the participant withdrawals and updated supporting modeling. On August 27, 2008, the NDPSC approved Montana-Dakota’s request for advance determination of prudence for ownership in the proposed Big Stone Station II for a minimum of 121.8 MW up to a maximum of 133 MW and a proportionate ownership share of the associated transmission electric resources. On September 26, 2008, the intervenors in the proceeding appealed the NDPSC order to the North Dakota District Court. The appeal was assigned and a briefing schedule was established. The intervenors brief was filed January 16, 2009, and Montana-Dakota’s brief is due in February 2009.
In December 1999, Williston Basin filed a general natural gas rate change application with the FERC. Williston Basin began collecting such rates effective June 1, 2000, subject to refund. Currently, the only remaining issue outstanding related to this rate change application is in regard to certain service restrictions. In May 2004, the FERC remanded this issue to an ALJ for resolution. In November 2005, the FERC issued an Order on Initial Decision affirming the ALJ's Initial Decision regarding certain service and annual demand quantity restrictions. In April 2006, the FERC issued an Order on Rehearing denying Williston Basin's Request for Rehearing of the FERC's Order on Initial Decision. In April 2006, Williston Basin appealed to the D.C. Appeals Court certain issues addressed by the FERC's Order on Initial Decision and its Order on Rehearing. On March 18, 2008, the D.C. Appeals Court issued its opinion in this matter concerning the service restrictions. The D.C. Appeals Court found that the FERC was correct to decide the case under the “just and reasonable” standard of section 5(a) of the Natural Gas Act; however, it remanded the case back to the FERC as flaws in the FERC’s reasoning render its orders arbitrary and capricious. On December 18, 2008, the FERC issued its Order Requesting Data and Comment on this matter. Williston Basin and Northern States Power Company provided responses to FERC’s requests in January 2009. In addition, initial comments addressing specific issues identified by the FERC are due to be filed by February 15, 2009, with reply comments due by March 7, 2009. The initial and reply comments should contain all the arguments and supporting evidence the parties determine they need to provide to update the record with regard to the issue under remand.
NOTE 20 - COMMITMENTS AND CONTINGENCIES
Litigation
Coalbed Natural Gas Operations Fidelity is a party to and/or certain of its operations are or have been the subject of more than a dozen lawsuits in Montana and Wyoming in connection with Fidelity’s CBNG development in the Powder River Basin. The lawsuits generally involve either challenges to regulatory agency decisions under the NEPA or the MEPA or to Fidelity’s management of water produced in association with its operations.
Challenges to State/Federal Regulatory Agency Decision Making Under NEPA/MEPA
In 1999 and 2000, the BLM, the Montana BOGC, and the Montana DEQ announced their respective decisions to prepare an EIS analyzing CBNG development in Montana. In 2003, the agencies each signed RODs approving a final EIS and allowing CBNG development throughout the State of Montana. The approval actions by the agencies resulted in numerous lawsuits initiated by environmental groups and the Northern Cheyenne Tribe related to the validity of the final EIS and associated environmental assessments. Fidelity has intervened in several of these lawsuits to protect its interests.
In lawsuits filed in Montana Federal District Court in May 2003, the NPRC and the Northern Cheyenne Tribe asserted that the BLM violated NEPA and other federal laws when approving the 2003 EIS. As a result of an order entered in those lawsuits, producers, including Fidelity, were allowed to engage in limited CBNG development of up to 500 CBNG wells to be drilled annually on private, state, and federal lands in the Montana Powder River Basin pending the BLM's preparation and adoption of a SEIS. As provided in the order, the injunction limiting development expired on January 14, 2009.
In December 2006, the BLM issued a draft SEIS that endorsed a phased-development approach to CBNG production in the Montana Powder River Basin, whereby future projects would be reviewed against four screens or filters (relating to water quality, wildlife, Native American concerns and air quality). Fidelity filed written comments on the draft SEIS asking the BLM to reconsider its proposed phased-development approach and to make numerous other changes to the draft SEIS. The final SEIS was released on October 31, 2008, and the related ROD was signed December 30, 2008. The final SEIS adopted a phased approach that is intended to reduce the overall cumulative impacts to any resource by managing the pace and place as well as the density and intensity of federal CBNG development. Among other limitations, the final SEIS includes a requirement to collect additional habitat data in order for the BLM to permit development in sage grouse crucial habitat areas. Fidelity believes that while permitting may be slower under the final SEIS, it should still be able to develop its CBNG resources at a pace sufficient to meet its investment objectives.
In a related action filed in Montana Federal District Court in December 2003, the NPRC asserted, among other things, that the actions of the BLM in approving Fidelity's applications for permits and the plan of development for the Badger Hills Project in Montana did not comply with applicable federal laws, including the NEPA. As a result of the litigation, Fidelity is operating under an Order, based on a stipulation between the parties, that allows production from existing wells in Fidelity’s Badger Hills Project to continue pending preparation of a revised environmental analysis. Fidelity does not believe the revised environmental analysis will have a material impact on its operations. While Fidelity anticipates the revised environmental analysis will be tiered to the final SEIS, Fidelity does not anticipate the revised environmental analysis will impact existing development. With regard to future development, Fidelity’s plans to drill in the Badger Hills Project are limited, and, as noted above, Fidelity believes it will be able to develop its CBNG resources at a pace sufficient to meet its investment objectives.
Cases Involving Fidelity’s Management of Water Produced in Association with Its Operations
About half the CBNG cases Fidelity is involved in relate to administrative agency regulation of water produced in association with CBNG development in Montana and Wyoming. These cases involve legal challenges to the issuance of discharge permits, as well as challenges to the State of Wyoming’s CBNG water permitting procedures.
In April 2006, the Northern Cheyenne Tribe filed a complaint in Montana State District Court against the Montana DEQ seeking to set aside Fidelity’s renewed direct discharge and treatment permits. The Northern Cheyenne Tribe claimed the Montana DEQ violated the Clean Water Act and the Montana Water Quality Act by failing to include in the permits conditions requiring application of the best practicable control technology currently available and by failing to impose a nondegradation policy like the one the BER adopted soon after the permit was issued. In addition, the Northern Cheyenne Tribe claimed that the actions of the Montana DEQ violated the Montana State Constitution’s guarantee of a clean and healthful environment, that the Montana DEQ’s related environmental assessment was invalid, that the Montana DEQ was required, but failed, to prepare an EIS and that the Montana DEQ failed to consider other alternatives to the
issuance of the permits. Fidelity, the NPRC and the TRWUA were granted leave to intervene in this proceeding. On December 9, 2008, the Montana State District Court decided the case in favor of Fidelity and the Montana DEQ in all respects, denying the motions of the Northern Cheyenne Tribe, TRWUA, and NPRC, and granting the cross-motions of the Montana DEQ and Fidelity in their entirety. As a result, Fidelity may continue to utilize its direct discharge and treatment permits. Any appeal must be filed by March 23, 2009.
Fidelity’s discharge of water pursuant to its two permits is its primary means for managing CBNG produced water. Fidelity believes that its discharge permits should, assuming normal operating conditions, allow Fidelity to continue its existing CBNG operations through the expiration of the permits in March 2011. If its permits are set aside, Fidelity’s CBNG operations in Montana could be significantly and adversely affected.
The Powder River Basin Resource Council is funding litigation, filed in Wyoming State District Court in June 2007, on behalf of two surface owners against the Wyoming State Engineer and the Wyoming Board of Control. The plaintiffs seek a declaratory judgment that current ground water permitting practices are unlawful; that the state is required to adopt rules and procedures to ensure that coalbed groundwater is managed in accordance with the Wyoming Constitution and other laws; and that would prohibit the Wyoming State Engineer from issuing permits to produce coalbed groundwater and permits to store coalbed groundwater in reservoirs until the Wyoming State Engineer adopts such rules. The Wyoming State District Court granted the Petroleum Association of Wyoming’s motion to intervene provided that the defendants motion to dismiss was denied. Fidelity is partly funding the intervention. On May 29, 2008, the Wyoming State District Court dismissed the case. The plaintiffs appealed to the Wyoming Supreme Court on June 27, 2008. Fidelity’s CBNG operations in Wyoming could be materially adversely affected if the plaintiffs are successful in this lawsuit.
Fidelity will continue to vigorously defend its interests in all CBNG-related litigation in which it is involved, including the proceedings challenging its water permits. In those cases where damage claims have been asserted, Fidelity is unable to quantify the damages sought and will be unable to do so until after the completion of discovery. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could adversely impact Fidelity’s existing CBNG operations and/or the future development of this resource in the affected regions.
Electric Operations Montana-Dakota joined with two electric generators in appealing a September 2003 finding by the ND Health Department that it may unilaterally revise operating permits previously issued to electric generating plants. Although it is doubtful that any revision of Montana-Dakota's operating permits by the ND Health Department would reduce the amount of electricity its plants could generate, the finding, if allowed to stand, could increase costs for sulfur dioxide removal and/or limit Montana-Dakota's ability to modify or expand operations at its North Dakota generation sites. Montana-Dakota and the other electric generators filed their appeal of the order in October 2003 in the North Dakota District Court. Proceedings were stayed pending conclusion of the periodic review of sulfur dioxide emissions in the state.
In September 2005, the ND Health Department issued its final periodic review decision based on its August 2005 final air quality modeling report. The ND Health Department concluded there were no violations of the sulfur dioxide increment in North Dakota. In March 2006, the DRC filed a complaint in Colorado Federal District Court seeking to force the EPA to declare that the increment had been violated based on earlier modeling conducted by the EPA. The EPA defended against the DRC claim and filed a motion to dismiss the case. The Colorado Federal District Court has dismissed the case.
In June 2007, the EPA noticed for public comment a proposed rule that would, among other things, adopt PSD increment modeling refinements that, if adopted, would operate to formally ratify the modeling techniques and conclusions contained in the September 2005 ND Health Department decision and the August 2005 final report.
In December 2008, the EPA indicated that the increment modeling rule would not be finalized. Because the EPA’s action does not alter the September 2005 final review decision of the ND Health Department, and because the DRC’s 2006 complaint was dismissed, the Company has determined the September 2003 finding by the ND Health Department will not have a material adverse impact on the Company and it does not intend to pursue the appeal of that finding.
On June 10, 2008, the Sierra Club filed a complaint in the South Dakota Federal District Court against Montana-Dakota and the two other co-owners of the Big Stone Station. The complaint alleges certain violations of the PSD and NSPS provisions of the Clean Air Act and certain violation of the South Dakota SIP. The action further alleges that the Big Stone Station was modified and operated without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. The Sierra Club alleges that these actions have contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. The Sierra Club seeks both declaratory and injunctive relief to bring the co-owners of the Big Stone Station into compliance with the Clean Air Act and the South Dakota SIP and to require them to remedy the alleged violations. The Sierra Club also seeks unspecified civil penalties, including a beneficial mitigation project. The Company believes that these claims are without merit and that Big Stone Station has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. The ultimate outcome of these matters cannot be determined at this time.
Natural Gas Storage Based on reservoir and well pressure data and other information, Williston Basin believes that reservoir pressure (and therefore the amount of gas) in the EBSR, one of its natural gas storage reservoirs, has decreased as a result of Howell and Anadarko’s drilling and production activities in areas within and near the boundaries of the EBSR. As of December 31, 2008, Williston Basin estimated that between 11.0 and 11.5 Bcf of storage gas had been diverted from the EBSR as a result of Howell and Anadarko’s drilling and production.
Williston Basin filed suit in Montana Federal District Court in January 2006, seeking to recover unspecified damages from Howell and Anadarko, and to enjoin Howell and Anadarko’s present and future production from specified wells in and near the EBSR. The Montana Federal District Court entered an Order in July 2006, dismissing the case for lack of subject matter jurisdiction. Williston Basin appealed and on May 9, 2008, the Ninth Circuit affirmed the Montana Federal District Court’s decision.
In related litigation, Howell filed suit in Wyoming State District Court against Williston Basin in February 2006 asserting that it is entitled to produce any gas that might escape from the EBSR. In August 2006, Williston Basin moved for a preliminary injunction to halt Howell and Anadarko’s production in and near the EBSR. The Wyoming State District Court denied Williston Basin’s motion in July 2007. In December 2007, motions were argued to a court appointed special master concerning the application of certain legal principles to the production of Williston Basin’s storage gas, including gas residing outside the certificated boundaries of the EBSR, by Howell and Anadarko. On March 17, 2008, the special master issued recommendations to the Wyoming State District Court. The special master recommended that the Wyoming State District Court adopt a
ruling that gas injected into an underground reservoir belongs to the injector and the injector does not lose title to that gas unless the gas escapes or migrates from the reservoir because it was not well defined or well maintained or if the injector is unable to identify such injected gas because it has been commingled with native gas. The special master also recommended that the Wyoming State District Court adopt a ruling that generally would allow Howell and Anadarko to produce native gas residing inside or outside the certificated boundaries of the EBSR from its wells completed outside the certificated boundaries. The special master recognized that there are other issues yet to be developed that may be determinative of whether Howell and Anadarko may produce native or injected gas, or both. On July 1, 2008, the Wyoming State District Court adopted the special master’s report. On July 16, 2008, Williston Basin filed a petition requesting the Wyoming Supreme Court to review a ruling by the Wyoming State District Court that the Natural Gas Act does not preempt the state law that permits an oil and gas producer to take gas that has been dedicated for use in a federally certificated gas storage reservoir. On August 5, 2008, the Wyoming Supreme Court denied the petition. The Wyoming State District Court has scheduled the case for trial beginning January 19, 2010.
In a related proceeding, the FERC issued an order on July 18, 2008, in response to a petition filed by Williston Basin on April 24, 2008, declaring that the certification of a storage facility under the Natural Gas Act conveys to the certificate holder the right to acquire native gas within the certificated boundaries of the storage facility. The FERC also concurred that state law precluding the certificate holder from acquiring the right to native gas would be preempted by federal law.
As previously noted, Williston Basin estimates that as of December 31, 2008, Howell and Anadarko had diverted between 11.0 and 11.5 Bcf from the EBSR. Although all of Howell’s wells are shut in and no longer producing gas, Williston Basin believes that its gas losses from the EBSR will continue until pressures in the various interconnected geologic formations equalize. Williston Basin continues to monitor and analyze the situation. At trial, Williston Basin will seek recovery based on the amount of gas that has been and continues to be diverted as well as on the amount of gas that must be recovered as a result of the equalization of the pressures of various interconnected geological formations.
Expert reports were filed with the Wyoming State District Court in January 2008. Supplemental and rebuttal expert reports were filed September 15, 2008. Williston Basin’s experts are of the opinion that all of the gas produced by Howell and Anadarko is Williston Basin's gas and will have to be replaced. Williston Basin’s experts estimate that the replacement cost of the gas produced by Howell and Anadarko through July 2008 is approximately $103 million if injection is completed by the end of the 2010 injection season. Williston Basin's experts also estimate that Williston Basin will expend $6.3 million to mitigate the damages that Williston Basin suffered during the period of Howell and Anadarko’s production if the replacement gas is injected by the end of the 2010 injection season. Williston Basin believes that its experts’ opinions are based on sound law, economics, reservoir engineering, geology and geochemistry. The expert reports filed by Howell and Anadarko claim that storage gas owned by Williston Basin has migrated outside the EBSR into areas in which Howell and Anadarko have oil and gas rights. They theorize that Williston Basin is accountable to Howell and Anadarko for the migration of such gas. Although Howell and Anadarko have not specified the amount of damages they seek to recover, Williston Basin believes Howell and Anadarko’s proposed methodology for valuing their alleged injury, if any, is flawed, inconsistent and lacking in factual and legal support.
Williston Basin intends to vigorously defend its rights and interests in these proceedings, to assess further avenues for recovery through the regulatory process at the FERC, and to pursue the
recovery of any and all economic losses it may have suffered. Williston Basin cannot predict the ultimate outcome of these proceedings.
In light of the actions of Howell and Anadarko, Williston Basin installed temporary compression at the site in 2006 in order to maintain deliverability into the transmission system. Williston Basin leased working gas for the 2007 - 2008 and 2008 - 2009 heating seasons to supplement its cushion gas. While installation of the additional compression and leasing working gas provide temporary relief, Williston Basin believes that the adverse physical and operational effects occasioned by the past and potential future loss of storage gas could threaten the operation and viability of the EBSR, impair Williston Basin’s ability to comply with the EBSR certificated operating requirements mandated by the FERC and adversely affect Williston Basin’s ability to meet its contractual storage and transportation service commitments to customers. In another effort to protect the viability of the EBSR, Williston Basin, on April 18, 2008, filed an application with the FERC to expand the boundaries of the EBSR. The proposed expansion includes the areas from which Howell and Anadarko are producing.
The Company also is involved in other legal actions in the ordinary course of its business. Although the outcomes of any such legal actions cannot be predicted, management believes that the outcomes with respect to these other legal proceedings will not have a material adverse effect upon the Company’s financial position or results of operations.
Environmental matters
Portland Harbor Site In December 2000, MBI was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by MBI from Georgia Pacific-West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include MBI or Georgia-Pacific West, Inc. Although the LWG originally estimated the overall remedial investigation and feasibility study would cost approximately $10 million, it is now anticipated, on the basis of costs incurred to date and delays attributable to an additional round of sampling and potential further investigative work, that such cost could increase to a total in excess of $60 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a record of decision has been published. The development of a proposed plan and ROD on the harbor site is not anticipated to occur until 2010, after which corrective action will be undertaken. MBI also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.
Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, MBI does not believe it is a Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for any and all liabilities incurred in relation to the above matters, pursuant to the terms of their sale agreement. MBI has entered into an agreement tolling the statute of limitation in connection with the LWG’s potential claim for contribution to the costs of the remedial investigation and feasibility study.
The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action.
Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade’s predecessors.
The first claim is for soil and groundwater contamination at a site in Oregon and was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. It is not known at this time what share of the cleanup costs will actually be borne by Cascade. Additional ecological risk assessment conducted by Cascade and other PRPs is expected to be completed in 2009. The results of the assessment may affect the selection and implementation of a cleanup alternative.
The second claim is for contamination at a site in Washington and was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants that will require further investigation and cleanup. A supplemental investigation is currently being conducted to better characterize the extent of the contamination. The supplemental investigation is expected to be completed in 2009. The data from the preliminary investigation indicates other current and former owners of properties and businesses in the vicinity of the site may also be responsible for the contamination. There is currently not enough information to estimate the potential liability associated with this claim.
The third claim is also for contamination at a site in Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade’s predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim.
To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers.
Operating leases
The Company leases certain equipment, facilities and land under operating lease agreements. The amounts of annual minimum lease payments due under these leases as of December 31, 2008, were $22.2 million in 2009, $18.2 million in 2010, $14.0 million in 2011, $10.2 million in 2012, $8.8 million in 2013 and $42.2 million thereafter. Rent expense was $35.3 million, $35.6 million and $23.1 million for the years ended December 31, 2008, 2007 and 2006, respectively.
Purchase commitments
The Company has entered into various commitments, largely natural gas and coal supply, purchased power, natural gas transportation and storage and construction materials supply contracts. These commitments range from one to 52 years. The commitments under these contracts as of December 31, 2008, were $662.2 million in 2009, $332.6 million in 2010, $269.4 million in 2011, $136.0 million in 2012, $90.5 million in 2013 and $268.1 million thereafter. Amounts purchased under various commitments for the years ended December 31, 2008, 2007 and 2006, were approximately $1.0 billion (including the acquisition of Intermountain as discussed in Note 2), $857.0 million (including the acquisition of Cascade as discussed in
Note 2) and $265.8 million, respectively. These commitments were not reflected in the Company's consolidated financial statements.
Guarantees
In connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent of any losses that Petrobras may incur from certain contingent liabilities specified in the purchase agreement. Centennial has agreed to unconditionally guarantee payment of the indemnity obligations to Petrobras for periods ranging up to five and a half years from the date of sale. The guarantee was required by Petrobras as a condition to closing the sale of MPX.
Centennial continues to guarantee CEM's obligations under a construction contract for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. As described in Note 3, Centennial Resources sold CEM in July 2007 to Bicent Power LLC, which has provided a $10 million bank letter of credit to Centennial in support of that guarantee obligation. The guarantee, which has no fixed maximum, expires when CEM has completed its obligations under the construction contract. Substantial completion of construction is expected to occur upon the passing of a recently completed air quality permit test, and the warranty period associated with this project will expire one year after the date of substantial completion of construction.
In addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas and oil price swap and collar agreement obligations. There is no fixed maximum amount guaranteed in relation to the natural gas and oil price swap and collar agreements as the amount of the obligation is dependent upon natural gas and oil commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the natural gas and oil price swap and collar agreements at December 31, 2008, expire in the years ranging from 2009 to 2011; however, Fidelity continues to enter into additional hedging activities and, as a result, WBI Holdings from time to time may issue additional guarantees on these hedging obligations. There was no amount outstanding by Fidelity at December 31, 2008. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.
Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts, a conditional purchase agreement and certain other guarantees. At December 31, 2008, the fixed maximum amounts guaranteed under these agreements aggregated $221.7 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $185.6 million in 2009; $1.8 million in 2010; $25.0 million in 2011; $2.3 million in 2012; $800,000 in 2013; $1.2 million in 2018; $1.0 million, which is subject to expiration 30 days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $1.5 million and was reflected on the Consolidated Balance Sheet at December 31, 2008. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.
Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies, materials obligations, natural gas transportation agreements and other agreements that guarantee the performance of other subsidiaries of the Company. At December 31, 2008, the fixed maximum amounts guaranteed under these letters of credit, which expire in 2009, aggregated $36.8 million. There were no amounts outstanding under the above letters of credit at December 31, 2008.
Fidelity and WBI Holdings have outstanding guarantees to Williston Basin. These guarantees are related to natural gas transportation and storage agreements that guarantee the performance of Prairielands. At December 31, 2008, the fixed maximum amounts guaranteed under these agreements aggregated $24.0 million. Scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $20.0 million in 2009 and $4.0 million in 2011. In the event of Prairielands’ default in its payment obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee. The amount outstanding by Prairielands under the above guarantees was $1.8 million, which was not reflected on the Consolidated Balance Sheet at December 31, 2008, because these intercompany transactions are eliminated in consolidation.
In addition, Centennial and Knife River have issued guarantees to third parties related to the Company’s routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under its obligation in relation to the purchase of certain maintenance items, materials or lease obligations, Centennial or Knife River would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these maintenance items and materials were reflected on the Consolidated Balance Sheet at December 31, 2008.
In the normal course of business, Centennial has purchased surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. As of December 31, 2008, approximately $475 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.
SUPPLEMENTARY FINANCIAL INFORMATION
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter for the years 2008 and 2007:
Certain Company operations are highly seasonal and revenues from and certain expenses for such operations may fluctuate significantly among quarterly periods. Accordingly, quarterly financial information may not be indicative of results for a full year.
Natural Gas and Oil Activities (Unaudited)
Fidelity is involved in the acquisition, exploration, development and production of natural gas and oil resources. Fidelity's activities include the acquisition of producing properties with potential development opportunities, exploratory drilling and the operation and development of production properties. Fidelity shares revenues and expenses from the development of specified properties
located in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico in proportion to its ownership interests.
Fidelity owns in fee or holds natural gas leases for the properties it operates in Colorado, Montana, North Dakota, Texas, Utah and Wyoming. These rights are in the Bonny Field located in eastern Colorado, the Baker Field in southeastern Montana and southwestern North Dakota, the Bowdoin area located in north-central Montana, the Powder River Basin of Montana and Wyoming, the Bakken area in North Dakota, the Paradox Basin of Utah, the Tabasco and Texan Gardens fields of Texas and the Big Horn Basin in Wyoming. In 2008, Fidelity acquired and became the operator of natural gas properties in Rusk County in eastern Texas.
The information that follows includes Fidelity's proportionate share of all its natural gas and oil interests.
The following table sets forth capitalized costs and accumulated depreciation, depletion and amortization related to natural gas and oil producing activities at December 31:
Note: Net capitalized costs as of December 31, 2008, reflect a noncash write-down of the Company’s natural gas and oil properties as discussed in Note 1.
Capital expenditures, including those not subject to amortization, related to natural gas and oil producing activities were as follows:
* Excludes net additions to property, plant and equipment related to the recognition of future liabilities for asset retirement obligations associated with the plugging and abandonment of natural gas and oil wells, as discussed in Note 11, of $3.0 million, $5.4 million and $8.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.
** Includes expenditures for proved undeveloped reserves of $46.7 million, $74.6 million and $44.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.
The following summary reflects income resulting from the Company's operations of natural gas and oil producing activities, excluding corporate overhead and financing costs:
The following table summarizes the Company's estimated quantities of proved natural gas and oil reserves at December 31, 2008, 2007 and 2006, and reconciles the changes between these dates. Estimates of economically recoverable natural gas and oil reserves and future net revenues therefrom are based upon a number of variable factors and assumptions. For these reasons, estimates of economically recoverable reserves and future net revenues may vary from actual results.
Proved developed reserves:
The Company's interests in natural gas and oil reserves are located in the United States and in and around the Gulf of Mexico.
The standardized measure of the Company's estimated discounted future net cash flows of total proved reserves associated with its various natural gas and oil interests at December 31 was as follows:
The following are the sources of change in the standardized measure of discounted future net cash flows by year:
The estimated discounted future cash inflows from estimated future production of proved reserves were computed using year-end natural gas and oil prices. Future development and production costs attributable to proved reserves were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. Future development costs estimated to be spent in each of the next three years to develop proved undeveloped reserves as of December 31,
2008, are $115.6 million in 2009, $87.7 million in 2010 and $45.3 million in 2011. Future income tax expenses were computed by applying statutory tax rates, adjusted for permanent differences and tax credits, to estimated net future pretax cash flows.
The standardized measure of discounted future net cash flows does not purport to represent the fair market value of natural gas and oil properties. There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. In addition, future realization of natural gas and oil prices over the remaining reserve lives may vary significantly from current prices.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
The following information includes the evaluation of disclosure controls and procedures by the Company's chief executive officer and the chief financial officer, along with any significant changes in internal controls of the Company.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to management, including the Company's chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. The Company's chief executive officer and chief financial officer have evaluated the effectiveness of the Company's disclosure controls and procedures and they have concluded that, as of the end of the period covered by this report, such controls and procedures were effective.
CHANGES IN INTERNAL CONTROLS
The Company maintains a system of internal accounting controls that is designed to provide reasonable assurance that the Company's transactions are properly authorized, the Company's assets are safeguarded against unauthorized or improper use, and the Company's transactions are properly recorded and reported to permit preparation of the Company's financial statements in conformity with generally accepted accounting principles in the United States of America. There were no changes in the Company's internal control over financial reporting that occurred during the quarter ended December 31, 2008, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The information required by this item is included in this Form 10-K at Item 8 - Management's Report on Internal Control Over Financial Reporting.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
The information required by this item is included in this Form 10-K at Item 8 - Report of Independent Registered Public Accounting Firm.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is included under the captions "Item 1. Election of Directors - Director Nominees for One Year Term," "Continuing Incumbent Directors," "Information Concerning Executive Officers," the first paragraph, the second and third sentences of the second paragraph and the third paragraph under "Corporate Governance - Audit Committee," "Corporate Governance - Code of Conduct," the last paragraph under "Corporate Governance - Board Meetings and Committees," the fifth paragraph under "Corporate Governance - Nominating and Governance Committee" and "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement, which information is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is included under the caption "Executive Compensation" in the Proxy Statement, which information is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
EQUITY COMPENSATION PLAN INFORMATION
The following table includes information as of December 31, 2008, with respect to the Company's equity compensation plans:
(1)
Consists of the 1992 Key Employee Stock Option Plan, the Non-Employee Director Long-Term Incentive Compensation Plan, the Long-Term Performance-Based Incentive Plan and the Non-Employee Director Stock Compensation Plan.
(2)
Includes 513,533 performance shares.
(3)
In addition to being available for future issuance upon exercise of options, 357,757 shares under the Non-Employee Director Long-Term Incentive Compensation Plan may instead be issued in connection with stock appreciation rights, restricted stock, performance units, performance shares or other equity-based awards, and 6,008,817 shares under the Long-Term Performance-Based Incentive Plan may instead be issued in connection with stock appreciation rights, restricted stock, performance units, performance shares or other equity-based awards.
(4)
This amount also includes 414,277 shares available for issuance under the Non-Employee Director Stock Compensation Plan. Under this plan, in addition to a cash retainer, nonemployee Directors are awarded 4,050 shares following the Company's annual meeting of stockholders. The Company's Chairman of the Board of Directors receives an additional $50,000 in stock under the plan each December as part of his retainer. Additionally, a nonemployee Director may acquire additional shares under the plan in lieu of receiving the cash portion of the Director's retainer or fees.
(5)
Consists of the 1998 Option Award Program and the Group Genius Innovation Plan.
(6)
In addition to being available for future issuance upon exercise of options, 219,550 shares under the Group Genius Innovation Plan may instead be issued in connection with stock appreciation rights, restricted stock, restricted stock units, performance units, performance stock or other equity-based awards.
The following equity compensation plans have not been approved by the Company's stockholders.
The 1998 Option Award Program
The 1998 Option Award Program is a broad-based plan adopted by the Board of Directors, effective February 12, 1998. The plan permits the grant of nonqualified stock options to employees of the Company and its subsidiaries. The maximum number of shares that may be issued under the plan is 3,795,330. Shares granted may be authorized but unissued shares, treasury shares, or shares purchased on the open market. Option exercise prices are equal to the market
value of the Company's shares on the date of the option grant. Optionees receive dividend equivalents on their options, with any credited dividends paid in cash to the optionee if the option vests, or forfeited if the option is forfeited. Vested options remain exercisable for one year following termination of employment due to death or disability and for three months following termination of employment for any other reason.
Unvested options are forfeited upon termination of employment. Subject to the terms and conditions of the plan, the plan's administrative committee determines the number of shares subject to options granted to each participant and the other terms and conditions pertaining to such options, including vesting provisions. All options become immediately exercisable in the event of a change in control of the Company.
In 1998, 337 options (adjusted for the three-for-two stock splits in July 1998, October 2003 and July 2006) were granted to each of approximately 2,200 employees. No officers received grants. These options vested on March 2, 2001. In 2001, 450 options (adjusted for the three-for-two stock splits in October 2003 and July 2006) were granted to each of approximately 5,900 employees. No officers received grants. These options vested on February 13, 2004. As of December 31, 2008, options covering 425,066 shares of common stock were outstanding under the plan and 2,119,635 shares remained available for future grant. Options covering 1,250,629 shares had been exercised.
The Group Genius Innovation Plan
The Group Genius Innovation Plan was adopted by the Board of Directors, effective May 17, 2001, to encourage employees to share ideas for new business directions for the Company and to reward them when the idea becomes profitable. Employees of the Company and its subsidiaries who are selected by the plan's administrative committee are eligible to participate in the plan. Officers and Directors are not eligible to participate. The plan permits the granting of nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance stock and other awards. The maximum number of shares that may be issued under the plan is 223,150. Shares granted under the plan may be authorized but unissued shares, treasury shares or shares purchased on the open market. Restricted stockholders have voting rights and, unless determined otherwise by the plan's administrative committee, receive dividends paid on the restricted stock. Dividend equivalents payable in cash may be granted with respect to options and performance shares. The plan's administrative committee determines the number of shares or units subject to awards, and the other terms and conditions of the awards, including vesting provisions and the effect of employment termination. Upon a change in control of the Company, all options and stock appreciation rights become immediately vested and exercisable, all restricted stock becomes immediately vested, all restricted stock units become immediately vested and are paid out in cash, and target payout opportunities under all performance units, performance stock, and other awards are deemed to be fully earned, with awards denominated in stock paid out in shares and awards denominated in units paid out in cash. As of December 31, 2008, 3,600 shares of stock had been granted to 64 employees.
The remaining information required by this item is included under the caption "Security Ownership” in the Proxy Statement, which is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is included under the captions “Related Person Transaction Disclosure” and “Corporate Governance - Director Independence” in the Proxy Statement, which information is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is included under the caption "Accounting and Auditing Matters" in the Proxy Statement, which information is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND EXHIBITS
Index to Financial Statements and Financial Statement Schedules
1. Financial Statements
The following consolidated financial statements required under this item are included under Item 8 - Financial Statements and Supplementary Data.
Page
Consolidated Statements of Income for each of the three years in the period ended December 31, 2008
Consolidated Balance Sheets at December 31, 2008 and 2007
Consolidated Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 2008
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2008
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
All other schedules are omitted because of the absence of the conditions under which they are required, or because the information required is included in the Company's Consolidated Financial Statements and Notes thereto.
3. Exhibits
Stock Purchase Agreement by and between Intermountain Industries, Inc. and MDU Resources Group, Inc., dated as of July 1, 2008, filed as Exhibit 2 to Form 10-Q for the quarter ended June 30, 2008, filed on August 7, 2008, in File No. 1-3480*
3(a)
Restated Certificate of Incorporation of the Company, as amended, dated May 17, 2007, filed as Exhibit 3.1 to Form 8-A/A, filed on June 27, 2007, in File No. 1-3480*
3(b)
Company Bylaws, as amended to date, filed as Exhibit 3.1 to Form 8-K dated November 13, 2008, filed on November 19, 2008, in File No. 1-3480*
4(a)
Indenture of Mortgage, dated as of May 1, 1939, as restated in the Forty-Fifth Supplemental Indenture, dated as of April 21, 1992, and the Forty-Sixth through Fiftieth Supplements thereto between the Company and the New York Trust Company (The Bank of New York, successor Corporate Trustee) and A. C. Downing (Douglas J. MacInnes, successor Co-Trustee), filed as Exhibit 4(a) to Form S-3, in Registration No. 33-66682; and Exhibits 4(e), 4(f) and 4(g) to Form S-8, in Registration No. 33-53896; and Exhibit 4(c)(i) to Form S-3, in Registration No. 333-49472; and Exhibit 4(e) to Form S-8, in Registration No. 333-112035*
4(b)
Rights Agreement, dated as of November 12, 1998, between the Company and Wells Fargo Bank Minnesota, N.A. (formerly known as Norwest Bank Minnesota, N.A.), Rights Agent, filed as Exhibit 4.1 to Form 8-A on November 12, 1998, in File No. 1-3480*
4(c)
Indenture, dated as of December 15, 2003, between the Company and The Bank of New York, as trustee, filed as Exhibit 4(f) to Form S-8 on January 21, 2004, in Registration No. 333-112035*
4(d)
Certificate of Adjustment to Purchase Price and Redemption Price, as amended and restated, pursuant to the Rights Agreement, dated as of November 12, 1998, filed as Exhibit 4(c) to Form 10-Q for the quarter ended June 30, 2006, filed on August 4, 2006, in File No. 1-3480*
4(e)
Centennial Energy Holdings, Inc. Master Shelf Agreement, dated April 29, 2005, among Centennial Energy Holdings, Inc. and the Prudential Insurance Company of America, filed as Exhibit 4(a) to Form 10-Q for the quarter ended June 30, 2005, filed on August 3, 2005, in File No. 1-3480*
4(f)
Letter Amendment No. 1 to Amended and Restated Master Shelf Agreement, dated May 17, 2006, among Centennial Energy Holdings, Inc., The Prudential Insurance Company of America, and certain investors described in the Letter Amendment filed as Exhibit 4(a) to Form 10-Q for the quarter ended June 30, 2006, filed on August 4, 2006, in File No. 1-3480*
4(g)
MDU Resources Group, Inc. Credit Agreement, dated June 21, 2005, among MDU Resources Group, Inc., Wells Fargo Bank, National Association, as Administrative Agent, and The Other Financial Institutions Party thereto, filed as Exhibit 4(b) to Form 10-Q for the quarter ended June 30, 2005, filed on August 3, 2005, in File No. 1-3480*
4(h)
First Amendment, dated June 30, 2006, to Credit Agreement, dated June 21, 2005, among MDU Resources Group, Inc., Wells Fargo Bank, National Association, as administrative agent, and certain lenders described in the credit agreement, filed as Exhibit 4(b) to Form 10-Q for the quarter ended June 30, 2006, filed on August 4, 2006, in File No. 1-3480*
4(i)
Centennial Energy Holdings, Inc. Credit Agreement, dated December 13, 2007, among Centennial Energy Holdings, Inc., U.S. Bank National Association, as Administrative Agent, and The Other Financial Institutions party thereto, filed as Exhibit 4(j) to Form 10-K for the year ended December 31, 2007, filed on February 20, 2008, in File No. 1-3480*
4(j)
MDU Energy Capital, LLC Master Shelf Agreement, dated as of August 9, 2007, among MDU Energy Capital, LLC and the Prudential Insurance Company of America, filed as Exhibit 4 to Form 8-K dated August 16, 2007, filed on August 16, 2007, in File No. 1-3480*
4(k)
Indenture dated as of August 1, 1992, between Cascade Natural Gas Corporation and The Bank of New York relating to Medium-Term Notes, filed by Cascade Natural Gas Corporation as Exhibit 4 to Form 8-K dated August 12, 1992, in File No. 1-7196*
4(l)
First Supplemental Indenture dated as of October 25, 1993, between Cascade Natural Gas Corporation and The Bank of New York relating to Medium-Term Notes and the 7.5% Notes due November 15, 2031, filed by Cascade Natural Gas Corporation as Exhibit 4 to Form 10-Q for the quarter ended June 30, 1993, in File No. 1-7196*
4(m)
Second Supplemental Indenture, dated January 25, 2005, between Cascade Natural Gas Corporation and The Bank of New York, as trustee, filed by Cascade Natural Gas Corporation as Exhibit 4.1 to Form 8-K dated January 25, 2005, filed on January 26, 2005, in File No. 1-7196*
4(n)
Third Supplemental Indenture dated as of March 8, 2007, between Cascade Natural Gas Corporation and The Bank of New York Trust Company, N.A., as Successor Trustee, filed by Cascade Natural Gas Corporation as Exhibit 4.1 to Form 8-K dated March 8, 2007, filed on March 8, 2007, in File No. 1-7196*
4(o)
Term Loan Agreement, dated September 26, 2008, among MDU Resources Group, Inc., Wells Fargo Bank, National Association, as Administrative Agent, and The Other Financial Institutions party thereto, filed as Exhibit 4(a) to Form 10-Q for the quarter ended September 30, 2008, filed on November 5, 2008, in File No. 1-3480*
4(p)
Amendment No. 1 to Master Shelf Agreement, dated October 1, 2008, among MDU Energy Capital, LLC, Prudential Investment Management, Inc., The Prudential Insurance Company of America, and the holders of the notes thereunder, filed as Exhibit 4(b) to Form 10-Q for the quarter ended September 30, 2008, filed on November 5, 2008, in File No. 1-3480*
+10(a)
Key Employee Stock Option Plan, as revised, filed as Exhibit 10(a) to Form 10-K for the year ended December 31, 2006, filed on February 21, 2007, in File No. 1-3480*
+10(b)
Supplemental Income Security Plan, as amended and restated, effective November 13, 2008**
+10(c)
Directors' Compensation Policy, as amended May 15, 2008, filed as Exhibit 10(b) to Form 10-Q for the quarter ended June 30, 2008, filed on August 7, 2008, in File No. 1-3480*
+10(d)
Deferred Compensation Plan for Directors, as amended May 15, 2008, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2008, filed on August 7, 2008, in File No. 1-3480*
+10(e)
Non-Employee Director Stock Compensation Plan, as amended May 15, 2008, filed as Exhibit 10(d) to Form 10-Q for the quarter ended June 30, 2008, filed on August 7, 2008, in File No. 1-3480*
+10(f)
Non-Employee Director Long-Term Incentive Compensation Plan, as amended May 15, 2008, filed as Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2008, filed on August 7, 2008, in File No. 1-3480*
+10(g)
Option Award Program, as revised, filed as Exhibit 10(q) to Form 10-K for the year ended December 31, 2006, filed on February 21, 2007, in File No. 1-3480*
+10(h)
Group Genius Innovation Plan, as revised, filed as Exhibit 10(r) to Form 10-K for the year ended December 31, 2006, filed on February 21, 2007, in File No. 1-3480*
10(i)
Purchase and Sale Agreement, dated January 4, 2008, between Fidelity and EnerVest Energy Institutional Fund IX, L.P., EnerVest Energy Institutional Fund IX-WI, L.P., and Everstar Energy, LLC, filed as Exhibit 10(o) to Form 10-K for the year ended December 31, 2007, filed on February 20, 2008, in File No. 1-3480*
+10(j)
WBI Holdings, Inc. Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended December 29, 2008**
+10(k)
Knife River Corporation Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended December 29, 2008**
+10(l)
Long-Term Performance-Based Incentive Plan, as revised, filed as Exhibit 10(y) to Form 10-K for the year ended December 31, 2006, filed on February 21, 2007, in File No. 1-3480*
+10(m)
MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended November 15, 2007, and Rules and Regulations, as amended November 12, 2008**
+10(n)
Montana-Dakota Utilities Co. Executive Incentive Compensation Plan, as amended November 15, 2007, and Rules and Regulations, as amended November 12, 2008**
+10(o)
Form of Change of Control Employment Agreement, as amended May 15, 2008, filed as Exhibit 10.1 to Form 8-K dated May 15, 2008, filed on May 20, 2008, in File No. 1-3480*
+10(p)
MDU Resources Group, Inc. Executive Officers with Change of Control Employment Agreements Chart, as of December 31, 2008**
+10(q)
Supplemental Executive Retirement Plan for John G. Harp, dated December 4, 2006, filed as Exhibit 10(ag) to Form 10-K for the year ended December 31, 2006, filed on February 21, 2007, in File No. 1-3480*
+10(r)
Employment Letter for John G. Harp, dated July 20, 2005, filed as Exhibit 10(ah) to Form 10-K for the year ended December 31, 2006, filed on February 21, 2007, in File No. 1-3480*
+10(s)
Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended August 13, 2008, filed as Exhibit 10.1 to Form 8-K dated August 13, 2008, filed on August 19, 2008, in File No. 1-3480*
+10(t)
MDU Construction Services Group, Inc. Executive Incentive Compensation Plan and Rules and Regulations, as amended January 31, 2008, filed as Exhibit 10(c) to Form 10-Q for the quarter ended March 31, 2008, filed on May 6, 2008, in File No. 1-3480*
+10(u)
John G. Harp 2008 additional incentive opportunity, filed as Exhibit 10(d) to Form 10-Q for the quarter ended March 31, 2008, filed on May 6, 2008, in File No. 1-3480*
Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends**
Subsidiaries of MDU Resources Group, Inc.**
Consent of Independent Registered Public Accounting Firm**
31(a)
Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**
31(b)
Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**
Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
Sales Agency Financing Agreement entered into between MDU Resources Group, Inc. and Wells Fargo Securities, LLC, filed as Exhibit 1 to Form 8-K dated September 5, 2008, filed on September 5, 2008, in File No. 1-3480*
------------------------
* Incorporated herein by reference as indicated.
** Filed herewith.
+ Management contract, compensatory plan or arrangement.
MDU Resources Group, Inc. agrees to furnish to the SEC upon request any instrument with respect to long-term debt that MDU Resources Group, Inc. has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MDU RESOURCES GROUP, INC.
Date:
February 13, 2009
By:
/s/ Terry D. Hildestad
Terry D. Hildestad
(President and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the date indicated.
Signature
Title
Date
/s/ Terry D. Hildestad
Chief Executive Officer and Director
February 13, 2009
Terry D. Hildestad
(President and Chief Executive Officer)
/s/ Vernon A. Raile
Chief Financial Officer
February 13, 2009
Vernon A. Raile
(Executive Vice President, Treasurer and Chief Financial Officer)
/s/ Doran N. Schwartz
Chief Accounting Officer
February 13, 2009
Doran N. Schwartz
(Vice President and Chief Accounting Officer)
/s/ Harry J. Pearce
Director
February 13, 2009
Harry J. Pearce
(Chairman of the Board)
/s/ Thomas Everist
Director
February 13, 2009
Thomas Everist
/s/ Karen B. Fagg
Director
February 13, 2009
Karen B. Fagg
/s/ A. Bart Holaday
Director
February 13, 2009
A. Bart Holaday
Director
Dennis W. Johnson
/s/ Thomas C. Knudson
Director
February 13, 2009
Thomas C. Knudson
/s/ Richard H. Lewis
Director
February 13, 2009
Richard H. Lewis
/s/ Patricia L. Moss
Director
February 13, 2009
Patricia L. Moss
/s/ John L. Olson
Director
February 13, 2009
John L. Olson
/s/ Sister Thomas Welder
Director
February 13, 2009
Sister Thomas Welder
/s/ John K. Wilson
Director
February 13, 2009
John K. Wilson