ITEM 3. LEGAL PROCEEDINGS
In January 2002, Fidelity Oil Co. (FOC), one of the Company's natural gas and oil production subsidiaries, entered into a compromise agreement with the former operator of certain of FOC's oil production properties in southeastern Montana. The compromise agreement resolved litigation involving the interpretation and application of contractual provisions regarding net proceeds interests paid by the former operator to FOC for a number of years prior to 1998. The terms of the compromise agreement are confidential. As a result of the compromise agreement, the natural gas and oil production segment reflected a nonrecurring gain in its financial results for the first quarter of 2002 of approximately $16.6 million after tax. As part of the settlement, FOC gave the former operator a full and complete release, and FOC is not asserting any such claim against the former operator for periods after 1997.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in United States District Court for the District of Columbia (U.S. District Court) against Williston Basin and over 70 other natural gas pipeline companies. Grynberg, acting on behalf of the United States under the Federal False Claims Act, alleged improper measurement of the heating content and volume of natural gas purchased by the defendants resulting in the underpayment of royalties to the United States. In March 1997, the U.S. District Court dismissed the suit without prejudice and the dismissal was affirmed by the United States Court of Appeals for the D.C. Circuit in October 1998. In June 1997, Grynberg filed a similar Federal False Claims Act suit against Williston Basin and Montana- Dakota and filed over 70 other separate similar suits against natural gas transmission companies and producers, gatherers, and processors of natural gas. In April 1999, the United States Department of Justice decided not to intervene in these cases. In response to a motion filed by Grynberg, the Judicial Panel on Multidistrict Litigation consolidated all of these cases in the Federal District Court of Wyoming (Federal District Court). Oral argument on motions to dismiss was held before the Federal District Court in March 2000. In May 2001, the Federal District Court denied Williston Basin's and Montana-Dakota's motion to dismiss. The matter is currently pending.
The Quinque Operating Company (Quinque), on behalf of itself and subclasses of gas producers, royalty owners and state taxing authorities, instituted a legal proceeding in State District Court for Stevens County, Kansas,(State District Court) against over 200 natural gas transmission companies and producers, gatherers, and processors of natural gas, including Williston Basin and Montana-Dakota. The complaint, which was served on Williston Basin and Montana-Dakota in September 1999, contains allegations of improper measurement of the heating content and volume of all natural gas measured by the defendants other than natural gas produced from federal lands. In response to a motion filed by the defendants in this suit, the Judicial Panel on Multidistrict Litigation transferred the suit to the Federal District Court for inclusion in the pretrial proceedings of the Grynberg suit. Upon motion of plaintiffs, the case has been remanded to State District Court. In September 2001, the defendants in this suit filed a motion to dismiss with the State District Court. The motion to dismiss was denied by the State District Court on August 19, 2002. The matter is currently pending.
Williston Basin and Montana-Dakota believe the claims of Grynberg and Quinque are without merit and intend to vigorously contest these suits. Williston Basin and Montana-Dakota believe it is not probable that Grynberg and Quinque will ultimately succeed given the current status of the litigation.
Fidelity Exploration & Production Company (Fidelity) has been named as a defendant in several lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. Fidelity believes the ultimate outcome of these actions will not have a material effect on its existing coalbed natural gas operations. However, if the plantiffs were successful, which Fidelity does not currently anticipate, the ultimate outcome of the actions could have a material effect on Fidelity's future development of its coalbed natural gas properties. For additional information regarding this matter, see Items 1 and 2 -- Business and Properties - Pipeline and Energy Services and Natural Gas and Oil Production and Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations.
In December 2000, MBI, an indirect wholly owned subsidiary of the Company, was named by the United States Environmental Protection Agency (EPA) as a Potentially Responsible Party in connection with the cleanup of a commercial property site, now owned by MBI, and part of the Portland, Oregon, Harbor Superfund Site. For additional information regarding this matter, see Items 1 and 2 -- Business and Properties - Construction Materials and Mining.
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 2002.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed on the New York Stock Exchange and the Pacific 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 2002 and 2001 and dividends declared thereon were as follows:
Common Common Common Stock Stock Price Stock Price Dividends (High) (Low) Per Share
First Quarter $ 31.09 $ 27.25 $ .23 Second Quarter 33.45 25.75 .23 Third Quarter 27.40 18.00 .24 Fourth Quarter 25.99 20.91 .24 $ .94
First Quarter $ 35.76 $ 27.38 $ .22 Second Quarter 40.37 31.38 .22 Third Quarter 32.90 22.38 .23 Fourth Quarter 28.30 23.00 .23 $ .90
As of December 31, 2002, the Company's common stock was held by approximately 14,000 stockholders of record.
Between October 1, 2002 and December 31, 2002, the Company issued 230,205 shares of Common Stock, $1.00 par value, as partial consideration with respect to an acquisition during this period. The Common Stock issued by the Company in this transaction was issued in private sales exempt from registration pursuant to Section 4(2) of the Securities Act of 1933. The former owners of the business acquired, and now shareholders of the Company, are accredited investors and have acknowledged that they would hold the Company's Common Stock as an investment and not with a view to distribution.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to Selected Financial Data on pages 80 and 81 of the Company's Annual Report which is incorporated herein by reference.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Prior to the fourth quarter of 2002, the Company reported six business segments consisting of electric, natural gas distribution, utility services, pipeline and energy services, natural gas and oil production and construction materials and mining. During the fourth quarter of 2002, the Company added an additional segment, independent power production, based on the significance of this segment's operations. Substantially all of the operations of the independent power production segment began in 2002, therefore financial information for years prior to 2002 has not been presented.
The Company's operations are now conducted through seven business segments. For purposes of segment financial reporting and discussion of results of operations, electric and natural gas distribution include the electric and natural gas distribution operations of Montana-Dakota and the natural gas distribution operations of Great Plains Natural Gas Co. Utility services includes all the operations of Utility Services, Inc. Pipeline and energy services includes WBI Holdings' natural gas transportation, underground storage, gathering services, and energy related management services. Natural gas and oil production includes the natural gas and oil acquisition, exploration and production operations of WBI Holdings. Construction materials and mining includes the results of Knife River's operations, while independent power production includes electric generating facilities in the United States and Brazil and also invests in potential new growth and synergistic opportunities that are not directly being pursued by other business segments.
Reference should be made to Items 1 and 2 -- Business and Properties, Item 3 -- Legal Proceedings and Notes to Consolidated Financial Statements for information pertinent to various commitments and contingencies.
Overview
The following table (dollars in millions, where applicable) summarizes the contribution to consolidated earnings by each of the Company's business segments.
Years ended December 31, 2002 2001 2000 Electric $ 15.8 $ 18.7 $ 17.7 Natural gas distribution 3.6 .7 4.8 Utility services 6.4 12.9 8.6 Pipeline and energy services 19.1 16.4 10.5 Natural gas and oil production 53.2 63.2 38.6 Construction materials and mining 48.7 43.2 30.1 Independent power production .9 --- --- Earnings on common stock $ 147.7 $ 155.1 $ 110.3
Earnings per common share - basic $ 2.09 $ 2.31 $ 1.80
Earnings per common share - diluted $ 2.07 $ 2.29 $ 1.80
Return on average common equity 12.5% 15.3% 14.3%
2002 compared to 2001
Consolidated earnings for 2002 decreased $7.4 million from the comparable period a year ago due to lower earnings at the natural gas and oil production, utility services and electric businesses. Increased earnings at the construction materials and mining, natural gas distribution and pipeline and energy services businesses, along with earnings from the independent power production business, partially offset the earnings decline.
2001 compared to 2000
Consolidated earnings for 2001 increased $44.8 million from the comparable period a year ago due to higher earnings from the natural gas and oil production, construction materials and mining, pipeline and energy services, utility services and electric businesses. Lower earnings at the natural gas distribution business partially offset the earnings increase.
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Financial and Operating Data
The following tables (dollars in millions, where applicable) are key financial and operating statistics for each of the Company's business segments.
Electric Years ended December 31, 2002 2001 2000 Operating revenues: Retail sales $ 142.1 $ 137.3 $ 134.5 Sales for resale and other 20.5 31.5 27.1 162.6 168.8 161.6 Operating expenses: Fuel and purchased power 56.0 57.4 54.1 Operation and maintenance 46.0 45.6 42.5 Depreciation, depletion and amortization 19.6 19.5 19.1 Taxes, other than income 7.1 7.6 7.1 128.7 130.1 122.8
Operating income $ 33.9 $ 38.7 $ 38.8
Retail sales (million kWh) 2,275.0 2,177.9 2,161.3 Sales for resale (million kWh) 784.6 898.2 930.3 Average cost of fuel and purchased power per kWh $ .018 $ .018 $ .016
Natural Gas Distribution Years ended December 31, 2002 2001 2000 Operating revenues: Sales $ 182.5 $ 251.3 $ 229.2 Transportation and other 4.1 4.1 3.9 186.6 255.4 233.1 Operating expenses: Purchased natural gas sold 132.9 200.7 178.6 Operation and maintenance 36.5 36.6 32.0 Depreciation, depletion and amortization 9.9 9.4 8.4 Taxes, other than income 4.9 5.1 4.6 184.2 251.8 223.6
Operating income $ 2.4 $ 3.6 $ 9.5
Volumes (MMdk): Sales 39.6 36.5 36.6 Transportation 13.7 14.3 14.3 Total throughput 53.3 50.8 50.9
Degree days (% of normal) 101.1% 94.5% 100.4% Average cost of natural gas, including transportation thereon, per dk $ 3.22 $ 5.50 $ 4.88
Utility Services
Years ended December 31, 2002 2001 2000
Operating revenues $ 458.7 $ 364.8 $ 169.4
Operating expenses: Operation and maintenance 419.0 321.0 142.6 Depreciation, depletion and amortization 9.9 8.4 4.9 Taxes, other than income 15.8 10.2 5.3 444.7 339.6 152.8
Operating income $ 14.0 $ 25.2 $ 16.6
Pipeline and Energy Services
Years ended December 31, 2002 2001 2000 Operating revenues: Pipeline $ 95.3 $ 87.1 $ 77.4 Energy services 69.9 444.0 559.4 165.2 531.1 636.8 Operating expenses: Purchased natural gas sold 58.3 433.5 548.3 Operation and maintenance 47.3 47.1 39.1 Depreciation, depletion and amortization 14.8 14.3 15.3 Taxes, other than income 5.7 5.8 5.3 126.1 500.7 608.0
Operating income $ 39.1 $ 30.4 $ 28.8
Transportation volumes (MMdk): Montana-Dakota 33.3 34.1 30.6 Other 66.6 63.1 56.2 99.9 97.2 86.8
Gathering volumes (MMdk) 72.7 61.1 41.7
Natural Gas and Oil Production
Years ended December 31, 2002 2001 2000 Operating revenues: Natural gas $ 131.1 $ 153.3 $ 84.7 Oil 44.9 50.2 43.4 Other 27.6* 6.3 10.2 203.6 209.8 138.3 Operating expenses: Purchased natural gas sold .1 2.8 3.4 Operation and maintenance 55.6 50.4 31.3 Depreciation, depletion and amortization 48.7 41.7 27.0 Taxes, other than income 13.6 11.0 10.1 118.0 105.9 71.8
Operating income $ 85.6 $ 103.9 $ 66.5
Production: Natural gas (MMcf) 48,239 40,591 29,222 Oil (000's of barrels) 1,968 2,042 1,882
Average realized prices: Natural gas (per Mcf) $ 2.72 $ 3.78 $ 2.90 Oil (per barrel) $ 22.80 $ 24.59 $ 23.06 ______________________________
* Includes the effects of a nonrecurring compromise agreement of $27.4 million ($16.6 million after tax) in the first quarter of 2002.
Construction Materials and Mining
Years ended December 31, 2002 2001 2000 Operating revenues: Construction materials $ 962.3 $ 794.6 $ 597.7 Coal ---** 12.3** 33.7 962.3 806.9 631.4 Operating expenses: Operation and maintenance 797.7 673.1 526.0 Depreciation, depletion and amortization 54.4 46.6 36.2 Taxes, other than income 18.8 15.7 12.4 870.9 735.4 574.6
Operating income $ 91.4 $ 71.5 $ 56.8
Sales (000's): Aggregates (tons) 35,078 27,565 18,315 Asphalt (tons) 7,272 6,228 3,310 Ready-mixed concrete (cubic yards) 2,902 2,542 1,696 Coal (tons) ---** 1,171** 3,111 ______________________________
** Coal operations were sold effective April 30, 2001.
Independent Power Production
Years ended December 31, 2002* 2001 2000
Operating revenues $ 6.8 $ --- $ ---
Operating expenses: Operation and maintenance 6.4 --- --- Depreciation, depletion and amortization .7 --- --- 7.1 --- ---
Operating loss $ (.3) $ --- $ ---
Electricity produced and sold (million kWh) 15.8 --- --- ______________________________
* Reflects international operations for 2002 and domestic operations acquired in November 2002. The earnings from the Company's equity method investment in Brazil were included in other income - net.
Amounts presented in the preceding tables for operating revenues, purchased natural gas sold and operation and maintenance expense will not agree with the Consolidated Statements of Income due to the elimination of intercompany transactions between the pipeline and energy services segment and the natural gas distribution, utility services, construction materials and mining, natural gas and oil production and independent power production segments. The amounts relating to the elimination of intercompany transactions for operating revenues, purchased natural gas sold, and operation and maintenance expense are as follows: $114.3 million, $98.8 million and $15.5 million for 2002; $113.2 million, $107.7 million and $5.5 million for 2001; and $96.9 million, $96.0 million and $.9 million for 2000, respectively.
2002 compared to 2001
Electric
Electric earnings decreased as a result of lower average realized sales for resale prices, which were 34 percent lower than last year, due to weaker demand in the sales for resale markets; the absence in 2002 of 2001 insurance recovery proceeds related to a 2000 outage at an electric generating station; and lower sales for resale volumes, which were 13 percent lower than last year. Partially offsetting the earnings decline were increased retail sales volumes, which were 4 percent higher than last year, primarily to residential, commercial and large industrial customers; decreased fuel and purchased power costs, largely lower demand charges resulting from the absence of a 2001 extended maintenance outage at an electric supplier's generating station; and increased retail sales prices, primarily demand revenue, which were partially offset by the North Dakota retail rate reduction. For further information on the North Dakota retail rate reduction, see Note 16 of Notes to Consolidated Financial Statements.
Natural Gas Distribution
Earnings at the natural gas distribution business increased as a result of higher retail sales volumes, which were 8 percent higher than last year, largely the result of weather that was 9 percent colder than the prior year; increased return on natural gas storage, demand and prepaid commodity balances; increased retail sales prices, largely the result of rate increases in Minnesota, Montana and North Dakota; higher service and repair margins; and lower income taxes, largely the result of the reversal of certain tax contingency reserves. A reserve adjustment of $3.3 million (after tax) related to certain pipeline capacity charges partially offset the earnings increase. The pass- through of lower natural gas prices resulted in the decrease in sales revenues and purchased natural gas sold. For further information on the retail rate increases, see Note 16 of Notes to Consolidated Financial Statements.
Utility Services
Utility services earnings decreased as a result of lower line construction margins in the Rocky Mountain region related primarily to decreased fiber optic construction work; lower construction margins in the Central region due to decreased inside electrical work; the write-off of certain receivables and restructuring of the engineering function of approximately $5.2 million (after tax); and decreased equipment sales and margins. Partially offsetting the earnings decline were increased workloads in the Southwest and Northwest regions, the discontinuance of the amortization of goodwill in 2002 ($1.4 million after tax in 2001), and decreased interest expense, primarily due to lower debt balances. The increase in revenues and the related increase in operation and maintenance expense resulted largely from businesses acquired since the comparable period last year.
Pipeline and Energy Services
Earnings at the pipeline and energy services business increased as a result of higher gathering revenues, largely increased gathering volumes, which were 19 percent higher than last year, at higher average rates, and higher stand-by fees; increased volumes transported on-system and off-system, at slightly higher average rates; and higher storage revenues. Also contributing to the earnings improvement were lower corporate development costs and the absence in 2002 of a 2001 write-off of an investment in a software development company of $699,000 (after tax). Partially offsetting the earnings increase were the net effects of the sale of certain smaller nonstrategic properties in 2001 along with higher operation and maintenance expense and higher depreciation, depletion and amortization expense, a result of the gathering system expansion to accommodate increasing natural gas volumes. The $374.1 million decrease in energy services revenue and the related decrease in purchased natural gas sold were due primarily to decreased energy marketing volumes resulting from the sale of the vast majority of the Company's energy marketing operations in the third quarter of 2001.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due to lower realized natural gas and oil prices, which were 28 percent and 7 percent lower than last year, respectively, along with lower oil production of 4 percent; partially offset by higher natural gas production of 19 percent, largely from operated properties in the Rocky Mountain area. Also adding to the earnings decline were increased depreciation, depletion and amortization expense due to higher natural gas production volumes and higher rates; increased operation and maintenance expense, mainly higher lease operating expenses resulting from the expansion of coalbed natural gas production; and lower sales volumes of inventoried natural gas. Partially offsetting the earnings decline were the effects of the nonrecurring compromise agreement of $27.4 million ($16.6 million after tax), included in operating revenues, as discussed in Note 17 of Notes to Consolidated Financial Statements. Hedging activities for natural gas and oil production for 2002 resulted in realized prices that were 107 percent and 98 percent, respectively, of what otherwise would have been received.
Construction Materials and Mining
Earnings for the construction materials and mining business increased as a result of earnings from businesses acquired since the comparable period last year; higher aggregate, asphalt and cement sales volumes; increased construction revenues, largely the result of several large projects mainly in California and Oregon; and lower asphalt costs. Partially offsetting the increase in earnings were the one-time gain in 2001 from the sale of the Company's coal operations of $10.3 million ($6.2 million after tax, including final settlement cost adjustments), included in other income - net, as discussed in Note 12 of Notes to Consolidated Financial Statements, as well as earnings from four months of coal operations included in 2001 earnings. Higher selling, general and administrative costs, mainly due to higher computer support, insurance and payroll costs; and higher depreciation, depletion and amortization expense due to higher sales volumes, partially offset by the discontinuance of the amortization of goodwill in 2002 ($1.7 million after tax in 2001), also added to the partial offset in earnings.
Independent Power Production
Earnings at the independent power production segment totaled $959,000. The majority of these earnings came from the newly acquired 213-megawatt natural gas-fired electric generating facilities in Colorado. The Brazilian operations also contributed to earnings. The Company's 49 percent share of the gain of $13.6 million (after tax) from an embedded derivative in the electric power contract and margins at the Brazil facilities were largely offset by the Company's 49 percent share of the foreign currency losses of $9.4 million (after tax) resulting from devaluation of the Brazilian real and net interest expense of $3.6 million (after tax).
2001 compared to 2000
Electric
Electric earnings increased due to higher average realized sales for resale prices, decreased interest expense due to lower average borrowings, and insurance recovery proceeds related to a 2000 outage at an electric generating station. Higher operation and maintenance expense, primarily increased payroll expense and higher subcontractor costs, and increased fuel and purchased power costs, largely higher demand charge costs related to an extended maintenance outage at an electric power supplier's generating station, partially offset the earnings increase. Also partially offsetting the earnings increase were lower sales for resale volumes, and increased depreciation, depletion and amortization expense resulting from higher property, plant and equipment balances.
Natural Gas Distribution
Earnings at the natural gas distribution business decreased as a result of lower sales volumes, largely the result of weather in the fourth quarter which was 22 percent warmer than a year ago, and higher operation and maintenance expenses, primarily increased payroll costs and higher bad debt expense. Lower average realized rates, return on natural gas storage, demand and prepaid commodity balances, and decreased service and repair margins also added to the earnings decline. Slightly offsetting the decline were decreased interest expense due to lower average borrowings, and earnings from a natural gas utility business acquired in July 2000. The pass-through of higher natural gas prices resulted in the increase in sales revenue and purchased natural gas sold.
Utility Services
Utility services earnings increased as a result of earnings from businesses acquired since the comparable period last year, slightly higher operating margins from existing operations and decreased interest expense due to lower average interest rates. The earnings improvement was partially offset by higher selling, general and administrative costs.
Pipeline and Energy Services
Earnings at the pipeline and energy services business increased due to higher transportation and gathering volumes at higher average rates at the pipeline. The absence in 2001 of an asset impairment recognized in 2000 in the amount of $3.9 million after tax at one of the Company's energy services companies and the net effect of the sale in 2001 of certain smaller nonstrategic properties at the pipeline also added to the earnings increase. In addition, higher natural gas sales margins at energy services added to the earnings increase. Partially offsetting the earnings increase were the absence in 2001 of a 2000 $6.7 million after-tax reserve revenue adjustment and resulting increase to income relating to certain regulatory proceedings, prior to the proceeding filed in 1999, and higher operation and maintenance expense. The write-off of an investment in a software development company of $699,000 (after tax) and expenses incurred for corporate development costs also partially offset the earnings increase. The higher operation and maintenance expense was due primarily to increased compressor-related expenses in connection with the expansion of the gathering systems. The decrease in energy services revenue and the related decrease in purchased natural gas sold resulted from decreased energy marketing sales volumes at certain energy services operations that were sold in 2001.
Natural Gas and Oil Production
Natural gas and oil production earnings increased largely due to higher natural gas and oil production of 39 percent and 9 percent since last year, respectively, combined with increased realized natural gas and oil prices, which were 30 percent and 7 percent higher than last year, respectively. The higher production was largely the result of a natural gas property acquisition in April 2000 and the ongoing development of that property as well as existing properties. Also adding to the earnings increase was lower interest expense, a result of lower debt balances combined with lower average rates. Partially offsetting the earnings improvement were increased operation and maintenance expense, mainly higher lease operating expenses and higher general and administrative costs. Increased depreciation, depletion and amortization expense due to higher production volumes and higher rates, and lower sales volumes of inventoried natural gas also partially offset the earnings increase. Hedging activities for natural gas and oil production for 2001 resulted in realized prices that were 101 percent and 104 percent, respectively, of what otherwise would have been received.
Construction Materials and Mining
Earnings for the construction materials and mining business increased largely due to earnings from businesses acquired since the comparable period last year and increases at existing asphalt, aggregate, cement and ready-mixed concrete construction materials operations. Also adding to the earnings increase was a one-time gain from the sale of the coal operations of $10.3 million ($6.2 million after tax, including final settlement cost adjustments), included in other income - net, as discussed in Note 12 of Notes to Consolidated Financial Statements, partially offset by lower coal sales volumes due primarily to four months of operations in 2001 compared to 12 months in 2000. Also partially offsetting the earnings increase were lower construction margins, largely resulting from increased competition and less available work, and the absence in 2001 of a 2000 gain of $1.2 million after tax on the sale of a nonstrategic property. Increased interest expense due to higher acquisition-related borrowings; higher depreciation, depletion and amortization expense due to increased plant balances; and higher selling, general and administrative costs also partially offset the earnings improvement.
Risk Factors and Cautionary Statements that May Affect Future Results
The Company is including the following factors and cautionary statements in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Prospective Information. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these factors and cautionary statements.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that the Company's expectations, beliefs or projections will be achieved or accomplished.
Any forward-looking statement contained in this document speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the effect of each such factor on the Company's business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.
Following are some specific factors that should be considered for a better understanding of the Company's financial condition. These 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.
The recent events leading to the current adverse economic environment may have a general negative impact on the Company's future revenues.
In response to the occurrence of several recent events, including the September 11, 2001, terrorist attack on the United States, the ongoing war against terrorism by the United States and the bankruptcy of several large energy and telecommunications companies, the financial markets have been disrupted. An adverse economy could negatively affect the level of governmental expenditures on public projects and the timing of these projects that, in turn, would negatively affect the demand for the Company's products and services.
Innovatum, Inc. (Innovatum), an indirect wholly owned subsidiary of the Company specializing in cable and pipeline magnetization and locating, is subject to the economic conditions within the telecommunications and energy industries. Innovatum could face a future goodwill impairment if there is a continued downturn in these sectors. At December 31, 2002, the goodwill amount at Innovatum was approximately $8.3 million. The determination of whether an impairment will occur is dependent on a number of factors, including the level of spending in the telecommunications and energy industries, the rapid changes in technology, competitors and potential new customers.
The Company's natural gas and oil production business is dependent on factors including commodity prices that cannot be predicted or controlled.
These factors include price fluctuations in natural gas and crude oil prices; availability of economic supplies of natural gas; drilling successes in natural gas and oil operations; the ability to contract for or to secure necessary drilling rig 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.
The Company's operations are weather sensitive.
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 and affect the ability to perform services at the utility services and construction materials and mining businesses. The Company cannot predict future weather conditions and as a result, adverse weather conditions could negatively affect the Company's operations and financial conditions.
The Company is subject to extensive environmental laws and regulations that may increase its 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, as a result of compliance, remediation, containment and monitoring obligations, particularly with regard to laws relating to power plant emissions and coalbed natural gas 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. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. The Company cannot predict the outcome (financial or operational) of any related litigation that may arise.
There are no assurances that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not 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 effect on the Company's results of operations.
Fidelity has been named as a defendant in several lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming. Fidelity believes the ultimate outcome of these actions would not have a material effect on its existing coalbed natural gas operations. However, if the plaintiffs are successful, which Fidelity does not currently anticipate, the ultimate outcome of the actions could have a material effect on Fidelity's future development of its coalbed natural gas properties.
The Company is subject to extensive government regulations that may have a negative impact on its business and its results of operations.
The Company is subject to regulation by federal, state and local regulatory agencies with respect to, among other things, allowed rates of return, financings, industry rate structures, 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 required to have numerous permits, approvals and certificates from the agencies that regulate its business. The Company believes the necessary permits, approvals and certificates have been obtained for existing operations and that the Company's business is conducted in accordance with applicable laws; however, 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.
The Company is dependent on its ability to successfully access capital markets. Inability to access capital may limit its ability to execute business plans, pursue improvements or make acquisitions that it may otherwise rely on for future growth.
The Company relies on access to both short-term borrowings, including the issuance of commercial paper, and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from its 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 or a downgrade of its credit ratings may increase the cost of borrowing or adversely affect its ability to access one or more financial markets. Such disruptions could include:
- A severe economic downturn - The bankruptcy of unrelated companies in the same line of business - Capital market conditions generally - Commodity prices - Terrorist attacks - Global events
There are risks involved with the growth strategies of the Company's independent power production business.
The operation of power generation facilities involves many risks, including start up risks, breakdown or failure of equipment, competition, inability to obtain required governmental permits and approvals and inability to negotiate acceptable acquisition, construction, fuel supply or other material agreements, as well as the risk of performance below expected levels of output or efficiency.
The Company's plans to construct a 113-megawatt coal-fired electric generation station in Montana are pending. The Company purchased plant equipment and obtained all permits necessary to begin construction. NorthWestern Energy terminated the power purchase agreement for the energy from this plant in July 2002; however, the Company is pursuing other markets for the energy and is studying its options regarding this project. The Company has suspended construction activities except for those items of a critical nature. At December 31, 2002, the Company's investment in this project was approximately $23.1 million. If it is not economically feasible for the Company to construct and operate this facility or if alternate markets cannot be identified, an asset impairment may occur.
The value of the Company's investment in foreign operations may diminish due to political, regulatory and economic conditions and changes in currency rates in countries where the Company does business.
The Company is subject to political, regulatory and economic conditions and changes in currency 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.
The Company's 49 percent equity method investment in a 200- megawatt natural gas-fired electric generation project in Brazil includes a power purchase agreement that contains an embedded derivative. This embedded derivative derives its value from an annual adjustment factor that largely indexes the contract capacity payments to the U.S. dollar. In addition, from time to time, other derivative instruments may be utilized. The valuation of these financial instruments, including the embedded derivative, can involve judgments, uncertainties and the use of estimates. As a result, changes in the underlying assumptions could affect the reported fair value of these instruments. These instruments could recognize financial losses as a result of volatility in the underlying fair values, or if a counterparty fails to perform.
Competition is increasing in all of the Company's businesses.
All of the Company's business segments are subject to increased competition. The independent power industry includes numerous strong and capable competitors, many of which have extensive experience in the operation, acquisition and development of power generation facilities. Utility 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 are also experiencing increased competitive pressures as a result of consumer demands, technological advances, deregulation, greater availability of natural gas-fired generation 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.
Other important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in forward-looking statements include:
- Acquisition and disposal of assets or facilities - Changes in operation and construction of plant facilities - Changes in present or prospective generation - Changes in anticipated tourism levels - The availability of economic expansion or development opportunities - Population growth rates and demographic patterns - Market demand for energy from plants or facilities - Changes in tax rates or policies - Unanticipated project delays or changes in project costs - Unanticipated changes in operating expenses or capital expenditures - Labor negotiations or disputes - Inflation rates - Inability of the various counterparties to meet their contractual obligations - Changes in accounting principles and/or the application of such principles to the Company - Changes in technology and legal proceedings - The ability to effectively integrate the operations of acquired companies
Prospective Information
The following information includes highlights of the key growth strategies, projections and certain assumptions for the Company and its subsidiaries over the next few years and other matters for each of the Company's seven business segments. Many of these highlighted points are forward-looking statements. There is no assurance that the Company's projections, including estimates for growth and increases in revenues and earnings, will in fact be achieved. Reference should be made to assumptions contained in this section as well as the various important factors listed under the heading Risk Factors and Cautionary Statements that May Affect Future Results. Changes in such assumptions and factors could cause actual future results to differ materially from targeted growth, revenue and earnings projections.
MDU Resources Group, Inc.
- - 2003 earnings per share, diluted, before the cumulative effect of an accounting change required by the implementation of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143) in the first quarter of 2003, are projected in the range of $1.80 to $2.05.
- - The Company expects the percentage of 2003 earnings per share before the cumulative effect of an accounting change by quarter to be in the following approximate ranges:
- First Quarter: 5 percent to 10 percent - Second Quarter: 20 percent to 25 percent - Third Quarter: 40 percent to 45 percent - Fourth Quarter: 25 percent to 30 percent
- - The Company will examine issuing equity from time to time to keep debt at the nonregulated businesses at no more than 40 percent of total capitalization.
- - The Company's long-term compound annual growth goals on earnings per share from operations are in the range of 6 percent to 9 percent.
Electric
- - Montana-Dakota has obtained and holds valid and existing franchises authorizing it to conduct its electric operations in all of the municipalities it serves where such franchises are required. As franchises expire, Montana-Dakota may face increasing competition in its service areas, particularly its service to smaller towns, from rural electric cooperatives. Montana-Dakota intends to protect its service area and seek renewal of all expiring franchises and will continue to take steps to effectively operate in an increasingly competitive environment.
- - A 40-megawatt natural gas-fired peaking unit is scheduled to be constructed for operation by June 1, 2003. This project is expected to be recovered in rates and will be used to meet the utility's need for additional generating capacity.
- - Pending regulatory approval, Montana-Dakota plans to purchase energy from a 20-megawatt wind energy farm in North Dakota. Rate recovery is expected.
- - Montana-Dakota is working with the state of North Dakota to determine the feasibility of constructing a 500-megawatt lignite- fired power plant in western North Dakota. In December 2002, Montana-Dakota confirmed its intent to continue the study, however, Montana-Dakota is also in the process of obtaining approval to include a 250-megawatt plant option within the study. The next preliminary decision is expected in late 2003.
Natural gas distribution
- - Montana-Dakota and Great Plains have obtained and hold valid and existing franchises authorizing them to conduct their natural gas operations in all of the municipalities they serve where such franchises are required. As franchises expire, Montana-Dakota and Great Plains may face increasing competition in their service areas. Montana-Dakota and Great Plains intend to protect their service areas and seek renewal of all expiring franchises and will continue to take steps to effectively operate in an increasingly competitive environment.
- - Annual natural gas throughput for 2003 is expected to be approximately 50 million decatherms.
- - Montana-Dakota or Great Plains have filed applications with state regulatory authorities in three states (Minnesota, Montana and South Dakota) seeking increases in natural gas retail rates that are in the range of 5.8 percent to 6.9 percent above current rates. While Montana-Dakota and Great Plains believe that they should be authorized to increase retail rates in the respective amounts requested, there is no assurance that the increases ultimately allowed will be for the full amounts requested in each jurisdiction. For further information on the natural gas rate increase applications, see Note 16 of Notes to Consolidated Financial Statements.
Utility services
- - Revenues for this segment are expected to be in the range of $450 million to $500 million in 2003. This segment anticipates margins in 2003 to increase over 2002 levels.
Pipeline and energy services
- - In 2003, natural gas throughput from this segment, including both transportation and gathering, is expected to increase slightly over the 2002 record level throughput.
- - A 247-mile pipeline to transport additional natural gas to market and enhance the use of this segment's storage facilities is currently under regulatory review. Depending upon the timing of receiving the necessary regulatory approval, completion of construction could occur in late 2003.
- - Innovatum could face a future goodwill impairment based on certain economic conditions, as previously discussed in Risk Factors and Cautionary Statements that May Affect Future Results.
Natural gas and oil production
- - In 2003, this segment expects a combined natural gas and oil production increase in excess of 20 percent over 2002 record levels.
- - This segment expects to drill in excess of 400 wells in 2003.
- - This segment had approximately 300 wells related to its coalbed natural gas development in the Powder River Basin in Montana and Wyoming that were not producing natural gas at December 31, 2002. A large number of these wells are expected to begin producing natural gas in 2003.
- - Natural gas prices in the Rocky Mountain region for February through December 2003 reflected in the Company's 2003 earnings guidance are in the range of $2.50 to $3.00 per Mcf. The Company's estimates for natural gas prices on the NYMEX for February through December 2003 reflected in the Company's 2003 earnings guidance are in the range of $3.00 to $3.50 per Mcf. During 2002, more than half of this segment's natural gas production was priced using Rocky Mountain or other non-NYMEX prices.
- - NYMEX crude oil prices for January through December 2003 reflected in the Company's 2003 earnings guidance are in the range of $20 to $25 per barrel.
- - This segment has hedged a portion of its 2003 production primarily using collars that establish both a floor and a cap. The Company has entered into agreements representing approximately 40 percent to 45 percent of 2003 estimated annual natural gas production. The agreements are at various indices and range from a low CIG index of $2.94 to a high Ventura index of $4.76 per Mcf.
- - The Company has hedged a portion of its 2003 oil production. The Company has entered into agreements at NYMEX prices with floors of $24.50 and caps as high as $28.12 per barrel, representing approximately 30 percent to 35 percent of 2003 estimated annual oil production.
- - Fidelity has been named as a defendant in several lawsuits filed in connection with its coalbed natural gas development in the Powder River Basin in Montana and Wyoming, as previously discussed in Risk Factors and Cautionary Statements that May Affect Future Results.
Construction materials and mining
- - Excluding the effects of potential future acquisitions, aggregate, asphalt and ready-mixed concrete volumes are expected to remain at or near the record levels achieved in 2002.
- - Revenues for this segment in 2003 are expected to be unchanged from 2002 record levels.
Independent power production
- - Earnings projections for 2003 for the independent power production segment include the estimated results from the previously mentioned wind-powered electric generation facility and the 2002 acquisition of generating facilities in Colorado, as well as earnings from the 200-megawatt natural gas-fired generation project in Brazil. Earnings from this segment are expected to be in the range of $12 million to $17 million in 2003.
- - On January 31, 2003, this segment purchased a 66.6-megawatt Mountain View wind-powered electric generating facility. The project sells all of its output under a long-term contract with the California Department of Water Resources.
- - The Company's plans to construct a 113-megawatt coal-fired electric generation station in Montana are pending as previously discussed in Risk Factors and Cautionary Statements that May Affect Future Results.
New Accounting Standards
In June 2001, the Financial Accounting Standards Board (FASB) approved SFAS No. 143. The adoption of SFAS No. 143 is expected to result in a one-time cumulative effect after-tax charge to earnings in the range of $7.0 million to $10.0 million and is also estimated to reduce 2003 earnings before the cumulative effect charge by approximately $1.6 million to $2.1 million. In addition, a regulatory asset that is approximated to be less than $1.0 million will be recognized for the transition amount that is expected to be recovered in rates over time. The Company intends to record the cumulative charge and regulatory asset in the first quarter of 2003.
In April 2002, the FASB approved Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). The Company believes the adoption of SFAS No. 145 will not have a material effect on its financial position or results of operations.
In June 2002, the FASB approved Statement of Financial Accounting Standards No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002, and is not expected to have a material effect on the Company's financial position or results of operations.
In September 2002, the Emerging Issues Task Force (EITF) issued consensus in EITF Issue No. 02-13, "Deferred Income Tax Considerations in Applying the Goodwill Impairment Test in FASB Statement No. 142, Goodwill and Other Intangible Assets" (EITF No. 02-13). EITF No. 02-13 did not have a material effect on the Company's goodwill impairment testing.
In October 2002, the EITF issued consensus in EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF No. 02-3). The adoption of EITF No. 02-3 did not have a material effect on the Company's financial position or results of operations.
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (Interpretation No. 45). The Company will apply the initial recognition and initial measurement provisions of Interpretation No. 45 to guarantees issued or modified after December 31, 2002.
In December 2002, the FASB approved Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123" (SFAS No. 148). The Company had adopted the disclosure provisions of SFAS No. 148 at December 31, 2002.
For further information on SFAS No. 143, SFAS No. 145, SFAS No. 146, EITF No. 02-13, EITF No. 02-3, Interpretation No. 45 and SFAS No. 148, see Note 1 of Notes to Consolidated Financial Statements.
Critical Accounting Policies
The Company has prepared its financial statements in conformity with accounting principles generally accepted in the United States of America, and these statements necessarily include some amounts that are based on informed judgments and estimates of management. The Company's significant accounting policies are discussed in Note 1 of Notes to Consolidated Financial Statements. The Company's critical accounting policies are subject to judgments and uncertainties which 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. In the event estimates or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. The Company's critical accounting policies include:
Impairment of long-lived assets and intangibles
The Company reviews the carrying values of its long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable and annually for goodwill as required by Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangibles." 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. Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, 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.
Impairment testing of natural gas and oil properties
The Company uses the full-cost method of accounting for its natural gas and oil production activities as discussed in Note 1 of Notes to Consolidated Financial Statements. The full-cost method of accounting requires judgments and assumptions to be made when estimating and valuing reserves using specific point in time natural gas and oil prices. Sustained downward movements in natural gas and oil prices and changes in estimates of reserve quantities could result in a future write-down of the Company's natural gas and oil properties.
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 probable. The Company's revenue recognition policy is discussed in Note 1 of Notes to Consolidated Financial Statements. 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. Estimates related to the recognition of revenue include the accumulated provision for revenues subject to refund, natural gas and oil revenues and costs on construction contracts under the percentage-of-completion method. 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.
Derivatives
Certain subsidiaries of the Company have cash flow hedging instruments comprised of natural gas price swap and natural gas and oil collar agreements and a foreign currency collar agreement that has not been designated as a hedge. The fair values of the natural gas price swap and natural gas and oil collar agreements and the foreign currency collar agreement have been recorded on the Company's balance sheet. The objective for holding the natural gas price swap and natural gas and oil collar agreements is to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on the Company's forecasted sale of natural gas and oil production. The objective for holding the foreign currency collar agreement is to manage a portion of the Company's foreign currency risk. For more information on the Company's derivative instruments, see Note 5 of Notes to Consolidated Financial Statements. Material changes to the Company's results of operations could occur if the hedging instrument is not highly effective in achieving offsetting cash flows attributable to the hedged risk or due to fluctuations in foreign currency exchange rates. The fair value of the derivative instruments is based on valuations determined by the counterparties. Changes in counterparty valuation assumptions and estimates could cause a material effect on the Company's financial position or results of operations.
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 recorded values of assets and liabilities are based 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.
Accounting for the effects of regulation
Substantially all of the Company's regulatory assets, other than certain deferred income taxes, are being reflected in rates charged to customers in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Regulation" (SFAS No. 71). 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. Consequently, the discontinuance of SFAS No. 71 could have a material effect on the Company's results of operations.
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 and 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; 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; the valuation of stock-based compensation; and the fair value of an embedded derivative in a power purchase agreement related to an equity method investment in Brazil as discussed in Note 2 of Notes to Consolidated Financial Statements. 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.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows provided by operating activities in 2002 decreased $22.2 million compared to 2001, largely the result of a decrease in cash from working capital items of $58.4 million. Higher depreciation, depletion and amortization expense of $18.0 million, resulting largely from increased property, plant and equipment balances, along with an increase in other noncurrent changes of $15.7 million partially offset the decrease in cash flows from operating activities.
In 2001, cash flows from operating activities increased $141.6 million compared to 2000, primarily due to an increase in net income of $44.8 million, and higher depreciation, depletion and amortization expense of $29.0 million, largely the result of increased acquisition-related property, plant and equipment balances. Also adding to the increase in operating cash flows was the increase in cash from changes in working capital items of $95.9 million.
Investing activities --
Cash flows used in investing activities in 2002 increased $6.2 million compared to 2001, the result of an increase in net capital expenditures (capital expenditures, acquisitions, net of cash acquired, and net proceeds from the sale or disposition of property) of $22.6 million and an increase in investments of $7.4 million, partially offset by a decrease in notes receivable of $23.8 million. Net capital expenditures exclude the noncash transactions related to acquisitions, including the issuance of the Company's equity securities. The noncash transactions were $47.2 million and $57.4 million for the years ended December 31, 2002 and 2001, respectively.
In 2001, cash flows used in investing activities decreased $49.0 million compared to 2000, primarily the result of a decrease in net capital expenditures of $67.2 million, partially offset by an increase in notes receivable of $18.8 million. Net capital expenditures exclude the following noncash transactions related to acquisitions: issuance of the Company's equity securities in 2001 and 2000 and the conversion of a note receivable to purchase consideration in 2000.
Financing activities --
Cash flows provided by financing activities in 2002 increased $48.8 million compared to 2001, primarily the result of the decrease of the repayment of long-term debt of $32.5 million and the net increase of short-term borrowings of $28.0 million, partially offset by the decrease in proceeds from issuance of common stock of $12.0 million.
In 2001, financing activities resulted in a decrease in cash flows of $144.3 million compared to 2000. This decrease was largely due to the increase of the repayment of long-term debt of $85.7 million, and the decrease of the issuance of long-term debt of $69.9 million. Partially offsetting the decrease was an increase in proceeds from issuance of common stock of $19.9 million.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit pension plans (Pension Plans). 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. During the year ended December 31, 2002, the market value of plan assets was negatively affected by persistent declines in the equity markets. At December 31, 2002, certain noncontributory defined benefit pension plans' accumulated benefit obligations exceeded these plans' assets by approximately $4.9 million. Pretax pension income reflected in the years ended December 31, 2002, 2001 and 2000, was $2.4 million, $4.4 million and $4.4 million, respectively. The change in pension income for the year ended December 31, 2003, is not expected to significantly affect earnings as a result of the impact of recent declines in the market value of Pension Plan assets. For further information on the Company's Pension Plans, see Note 14 of Notes to Consolidated Financial Statements.
Capital expenditures
The Company's capital expenditures (in millions) for 2000 through 2002 and as anticipated for 2003 through 2005 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term debt and preferred stock.
Actual Estimated* 2000 2001 2002 Capital expenditures: 2003 2004 2005 $ 15.8 $ 14.4 $ 27.8 Electric $ 32.7 $ 21.5 $ 26.8 21.3 14.7 11.0 Natural gas distribution 15.2 13.0 12.8 42.6 70.2 17.3 Utility services 10.5 10.4 11.2 Pipeline and energy 69.0 51.0 21.5 services 72.5 21.9 19.2 Natural gas and oil 173.5 118.7 136.4 production 123.0 112.1 107.1 Construction materials 218.7 170.6 106.9 and mining 48.6 52.9 49.1 Independent power --- --- 95.7 production 166.1 1.1 1.1 540.9 439.6 416.6 468.6 232.9 227.3 Net proceeds from sale or (11.0) (51.6) (16.2) disposition of property (4.9) (.8) (1.1) 529.9 388.0 400.4 Net capital expenditures 463.7 232.1 226.2
Retirement of long-term 29.4 115.2 82.6 debt and preferred stock 22.2 173.9 70.4 $559.3 $503.2 $483.0 $485.9 $406.0 $296.6 _________________________
*The estimated 2003 through 2005 capital expenditures reflected in the above table exclude potential future acquisitions other than the previously disclosed purchase of a 66.6-megawatt wind- powered electric generation facility. The Company continues to evaluate potential future acquisitions; however, these acquisitions are dependent upon the availability of economic opportunities and, as a result, capital expenditures may vary significantly from the above estimates.
Capital expenditures for 2002, 2001 and 2000, related to acquisitions, in the preceding table include the following noncash transactions: issuance of the Company's equity securities of $47.2 million in 2002; issuance of the Company's equity securities of $57.4 million in 2001; and issuance of the Company's equity securities and the conversion of a note receivable to purchase consideration of $132.1 million in 2000.
In 2002, the Company acquired a number of businesses, none of which was individually material, including utility services companies in California and Ohio, construction materials and mining businesses in Minnesota and Montana, an energy development company in Montana and natural gas-fired electric generation facilities in Colorado. The total purchase consideration for these businesses, consisting of the Company's common stock and cash, was $139.8 million.
The 2002 capital expenditures, including those for the previously mentioned acquisitions, and retirements of long-term debt and preferred stock, were met from internal sources, the issuance of long-term debt and the Company's equity securities. Capital expenditures for the years 2003 through 2005 include those for system upgrades, including a 40-megawatt natural gas-fired peaking unit, as previously discussed; routine replacements; service extensions; routine equipment maintenance and replacements; land and building improvements; pipeline and gathering expansion projects, including a 247-mile pipeline, as previously discussed; the further enhancement of natural gas and oil production and reserve growth; power generation opportunities, including the acquisition of a 66.6-megawatt wind-powered electric generation facility and construction of a 113-megawatt coal-fired electric generation station, both as previously discussed; and for 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 retirements of long-term debt and preferred stock for the years 2003 through 2005 will be met from various sources. These sources include internally generated funds, commercial paper credit facilities at Centennial and MDU Resources Group, Inc., 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, 2002.
MDU Resources Group, Inc.
The Company has unsecured short-term bank lines of credit from several banks totaling $46 million and a revolving credit agreement with various banks totaling $50 million at December 31, 2002. The bank lines of credit provide for commitment fees at varying rates and there were no amounts outstanding under the bank lines of credit or the credit agreement at December 31, 2002. The bank lines of credit and the credit agreement support the Company's $75 million commercial paper program. Under the Company's commercial paper program, $58.0 million was outstanding at December 31, 2002, of which $8.0 million was classified as short-term borrowings and $50.0 million was classified as long- term debt. The commercial paper borrowings classified as short term are supported by the short-term bank lines of credit. The commercial paper borrowings classified as long-term debt are intended to be refinanced on a long-term basis through continued Company commercial paper borrowings supported by the credit agreement, which allows for subsequent borrowings up to a term of one year. The Company intends to renew or replace the existing credit agreement, which expires December 30, 2003.
The Company's goal is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. If the Company were to experience a minor downgrade of its credit rating, it would not anticipate any change in its ability to access the capital markets. However, in such event, the Company would expect 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, which it does not currently anticipate, it may need to borrow under its credit agreement and/or bank lines of credit.
To the extent the Company needs to borrow under its credit agreement and/or its bank lines of credit, it would be expected to incur increased annualized interest expense on its variable rate debt of approximately $87,000 (after tax) based on December 31, 2002, variable rate borrowings. Based on the Company's overall interest rate exposure at December 31, 2002, this change would not have a material effect on the Company's results of operations or cash flows.
On an annual basis, the Company negotiates the placement of its credit agreement and bank lines of credit that provide credit support to access the capital markets. In the event the Company was unable to successfully negotiate the credit agreement and/or the bank lines of credit, or in the event the fees on such facilities became too expensive, which it does not currently anticipate, the Company would seek alternative funding. One source of alternative funding might involve the securitization of certain Company assets.
In order to borrow under the Company's credit agreement, the Company must be in compliance with the applicable covenants and certain other conditions. The significant covenants include maximum leverage ratios, minimum interest coverage ratio, limitation on sale of assets and limitation on investments. The Company was in compliance with these covenants and met the required conditions at December 31, 2002. In the event the Company does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued as previously described.
Currently, 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 Indenture of Mortgage. Generally, those restrictions require the Company to pledge $1.43 of unfunded property to the trustee for each dollar of indebtedness incurred under the Indenture and that annual earnings (pretax and before interest charges), as defined in the Indenture, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the two tests, as of December 31, 2002, the Company could have issued approximately $327 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred dividends was 4.8 times and 5.3 times for the years ended December 31, 2002 and 2001, respectively. Additionally, the Company's first mortgage bond interest coverage was 7.7 times and 8.5 times for the years ended December 31, 2002 and 2001, respectively. Common stockholders' equity as a percent of total capitalization was 60 percent and 58 percent at December 31, 2002 and 2001, respectively.
Centennial Energy Holdings, Inc.
Centennial has a revolving credit agreement with various banks that supports $305 million of Centennial's $350 million commercial paper program. There were no outstanding borrowings under the Centennial credit agreement at December 31, 2002. Under the Centennial commercial paper program, $101.9 million was outstanding at December 31, 2002. The Centennial commercial paper borrowings are classified as long term as Centennial intends to refinance these borrowings on a long-term basis through continued Centennial commercial paper borrowings and as further supported by the Centennial credit agreement, which allows for subsequent borrowings up to a term of one year. Centennial intends to renew the Centennial credit agreement, which expires September 26, 2003.
Centennial has an uncommitted long-term master shelf agreement that allows for borrowings of up to $400 million. Under the terms of the master shelf agreement, $360.6 million was outstanding at December 31, 2002. On January 17, 2003, Centennial borrowed an additional $39.0 million under the terms of this agreement. The $39.0 million in proceeds was used to pay down Centennial commercial paper program borrowings. In the future, Centennial intends to pursue other financing arrangements, including private and/or public financing.
Centennial's goal is to maintain acceptable credit ratings in order to access the capital markets through the issuance of commercial paper. If Centennial were to experience a minor downgrade of its credit rating, it would not anticipate any change in its ability to access the capital markets. However, in such event, Centennial would expect a nominal basis point increase in overall interest rates with respect to its cost of borrowings. If Centennial were to experience a significant downgrade of its credit ratings, which it does not currently anticipate, it may need to borrow under its committed bank lines.
To the extent Centennial needs to borrow under its committed bank lines, it would be expected to incur increased annualized interest expense on its variable rate debt of approximately $153,000 (after tax) based on December 31, 2002, variable rate borrowings. Based on Centennial's overall interest rate exposure at December 31, 2002, this change would not have a material effect on the Company's results of operations or cash flows.
On an annual basis, Centennial negotiates the placement of the Centennial credit agreement that provides credit support to access the capital markets. In the event Centennial was unable to successfully negotiate the credit agreement, or in the event the fees on such facility became too expensive, which Centennial does not currently anticipate, it would seek alternative funding. One source of alternative funding might involve the securitization of certain Centennial assets.
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. The significant covenants include maximum capitalization ratios, minimum interest coverage ratios, minimum consolidated net worth, limitation on priority debt, limitation on sale of assets and limitation on loans and investments. Centennial and such subsidiaries were in compliance with these covenants and met the required conditions at December 31, 2002. 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 as previously described.
The Centennial credit agreement and the Centennial uncommitted long-term master shelf agreement 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 Centennial credit agreement and the Centennial uncommitted long-term master shelf agreement will be in default. The Centennial credit agreement, the Centennial uncommitted long- term master shelf agreement and Centennial's practice limit the amount of subsidiary indebtedness.
International operations
A subsidiary of the Company, that has an investment in electric generating facilities in Brazil, has a short-term credit agreement that allows for borrowings of up to $25 million. Under this agreement, $12.0 million was outstanding at December 31, 2002. This subsidiary intends to renew this credit agreement, which expires June 30, 2003. Centennial has guaranteed this short-term credit agreement.
In order to borrow under the credit facility, the subsidiary must be in compliance with the applicable covenants and certain other conditions. The significant covenants include limitation on sale of assets and limitation on loans and investments. This subsidiary was in compliance with these covenants and met the required conditions at December 31, 2002. In the event this subsidiary does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf agreement that allows for borrowings of up to $100 million. Under the terms of the master shelf agreement, $30.0 million was outstanding at December 31, 2002.
In order to borrow under Williston Basin's uncommitted long- term master shelf agreement, it must be in compliance with the applicable covenants and certain other conditions. The significant covenants include limitation on consolidated indebtedness, limitation on priority debt, limitation on sale of assets and limitation on investments. Williston Basin was in compliance with these covenants and met the required conditions at December 31, 2002. In the event Williston Basin does not comply with the applicable covenants and other conditions, alternative sources of funding may need to be pursued.
Contractual obligations and commercial commitments
For more information on the Company's contractual obligations on long-term debt, operating leases and purchase commitments, see Notes 8 and 17 of Notes to Consolidated Financial Statements. At December 31, 2002, the Company's commitments under these obligations were as follows:
There- 2003 2004 2005 2006 2007 after Total (In millions)
Long-term debt $ 22.1 $173.8 $ 70.3 $100.2 $105.4 $369.8 $ 841.6 Operating leases 19.3 14.3 11.2 7.8 4.3 21.3 78.2 Purchase commitments 171.3 55.4 43.1 37.0 27.6 130.4 464.8
$212.7 $243.5 $124.6 $145.0 $137.3 $521.5 $1,384.6
Certain subsidiaries of the Company have financial guarantees outstanding at December 31, 2002. These guarantees as of December 31, 2002, are approximately $47.6 million, of which approximately $24.9 million pertain to Centennial's guarantee of certain obligations in connection with the natural gas-fired electric generation station in Brazil. For more information on these guarantees, see Notes 2 and 17 of Notes to Consolidated Financial Statements. As of December 31, 2002, with respect to these guarantees, there was approximately $43.2 million outstanding through 2003, $1.4 million outstanding through 2004 and $3.0 million outstanding thereafter. These guarantees are not reflected in the consolidated financial statements.
As of December 31, 2002, Centennial was contingently liable for performance of certain of its subsidiaries under approximately $200 million of surety bonds. These bonds are principally for construction contracts and reclamation obligations of these subsidiaries, entered into in the normal course of business. Centennial indemnifies the respective surety bond companies against any exposure under the bonds. A large portion of these contingent commitments expire in 2003, however Centennial will likely continue to enter into surety bonds for its subsidiaries in the future.
Approval of audit and nonaudit services
During the fourth quarter of 2002, the Company's Audit Committee pre-approved certain audit services relating to comfort letters and consents in connection with registration statements and other SEC required filings and audit reviews in connection with such filings, audit reviews in connection with business combinations, and additional audit services required in connection with quarterly reviews and annual audits. The Audit Committee also approved certain nonaudit services, relating to tax services in connection with domestic and international operations, and training on accounting and SEC compliance.
Effects of Inflation
Inflation did not have a significant effect on the Company's operations in 2002, 2001 or 2000.
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.
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 requires settlement of natural gas and oil price derivative instruments monthly, and that all interest rate derivative transactions must be settled over a period that will not exceed 90 days, and that 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. These policies and procedures include an evaluation of potential counterparties' credit ratings and credit exposure limitations. Accordingly, the Company does not anticipate any material effect to its financial position or results of operations as a result of nonperformance by counterparties.
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; or 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 will 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 other accumulated 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.
Commodity price risk --
A subsidiary of the Company utilizes natural gas and oil price swap and collar agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil on the subsidiary's forecasted sales of natural gas and oil production. Each of the natural gas and oil price swap and collar agreements were designated as a hedge of the forecasted sale of natural gas and oil production.
On an ongoing basis, the balance sheet is adjusted to reflect the current fair market value of the swap and collar agreements. The related gains or losses on these agreements are recorded in common stockholders' equity as a component of other comprehensive income (loss). At the date the underlying transaction occurs, 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 following table summarizes hedge agreements entered into by a wholly owned subsidiary of the Company, as of December 31, 2002. These agreements call for the subsidiary to receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted Average Notional Fixed Price Amount (Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap agreements maturing in 2003 $ 3.96 1,186 $(731)
Weighted Average Floor/Ceiling Notional Price Amount (Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar agreements maturing in 2003 $3.33/$3.89 22,365 $(6,256)
Weighted Average Floor/Ceiling Notional Price Amount (Per barrel) (In barrels) Fair Value
Oil collar agreements maturing in 2003 $24.50/$27.62 639 $(457)
The following table summarizes hedge agreements entered into by certain wholly owned subsidiaries of the Company, as of December 31, 2001. These agreements call for the subsidiaries to receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted Average Notional Fixed Price Amount (Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap agreement maturing in 2002 $ 4.34 1,150 $1,878
Weighted Average Notional Fixed Price Amount (Per barrel) (In barrels) Fair Value
Oil swap agreements maturing in 2002 $ 24.96 405 $1,789
Interest rate risk --
The Company uses fixed and variable rate long-term debt to partially finance capital expenditures and mandatory debt retirements. These debt agreements expose the Company to market risk related to changes in interest rates. The Company manages this risk by taking advantage of market conditions when timing the placement of long-term or permanent financing. The Company has also historically used interest rate swap agreements to manage a portion of the Company's interest rate risk and may take advantage of such agreements in the future to minimize such risk. As of December 31, 2002, the Company also has outstanding 13,000 shares of 5.10% Series preferred stock subject to mandatory redemption. The Company is obligated to make annual sinking fund contributions to retire the preferred stock and pay cumulative preferred dividends at a fixed rate of 5.10 percent.
The following table shows the amount of debt, including current portion, and related weighted average interest rates, both by expected maturity dates as well as the aggregate annual sinking fund amount applicable to preferred stock subject to mandatory redemption and the related dividend rate, as of December 31, 2002. Weighted average variable rates are based on forward rates as of December 31, 2002.
There- Fair 2003 2004 2005 2006 2007 after Total Value (Dollars in millions)
Long-term debt: Fixed rate $22.1 $ 21.9 $70.3 $100.2 $105.4 $369.8 $689.7 $742.7 Weighted average interest rate 7.4% 6.6% 8.0% 6.5% 8.2% 6.6% 7.0% -
Variable rate - $151.9 - - - - $151.9 $145.4 Weighted average interest rate - 1.5% - - - - 1.5% -
Preferred stock subject to mandatory redemption $ .1 $ .1 $ .1 $ .1 $ .1 $ .8 $ 1.3 $ 1.2 Dividend rate 5.1% 5.1% 5.1% 5.1% 5.1% 5.1% 5.1% -
For further information on derivative instruments and fair value of other financial instruments, see Notes 5 and 6 of Notes to Consolidated Financial Statements.
Foreign currency risk --
A subsidiary of the Company has a 49 percent equity investment in a 200-megawatt natural gas-fired electric generation project (Project) in Brazil, which has a portion of its borrowings and payables denominated in U.S. dollars. The subsidiary has exposure to currency exchange risk as a result of fluctuations in currency exchange rates between the U.S. dollar and the Brazilian real. The functional currency for the Project is the Brazilian real. For further information on this investment, see Note 2 of Notes to Consolidated Financial Statements.
The subsidiary's equity income from this Brazilian investment is impacted by fluctuations in currency exchange rates on transactions denominated in a currency other than the Brazilian real, including the effects of changes in currency exchange rates with respect to the Project's U.S. dollar denominated obligations, excluding a U.S. dollar denominated loan from the subsidiary as discussed below. At December 31, 2002, these U.S. dollar denominated obligations approximated $47.5 million. If, for example, the value of the Brazilian real decreased in relation to the U.S. dollar by 10 percent, the subsidiary, with respect to its interest in the Project, would record a foreign currency transaction loss in net income of approximately $2.1 million based on the above U.S. dollar denominated obligations at December 31, 2002. The Project also had US$27.6 million Brazilian real denominated obligations at December 31, 2002.
Adjustments attributable to the translation from the Brazilian real to the U.S. dollar for assets, liabilities, revenues and expenses were recorded in accumulated other comprehensive income at December 31, 2002.
The Project also had U.S. dollar denominated borrowings payable to the subsidiary of $20.0 million at December 31, 2002. Foreign currency translation adjustments on the Project's borrowings payable to the subsidiary are recorded in accumulated other comprehensive income.
The subsidiary's investment in this Project at December 31, 2002, was $27.8 million. Centennial has guaranteed Project obligations and loans of approximately $24.9 million as of December 31, 2002.
The subsidiary is managing a portion of its foreign currency exchange risk through contractual provisions, that are largely indexed to the U.S. dollar, contained in the Project's power purchase agreement with Petrobras. On August 12, 2002, the subsidiary entered into a foreign currency collar agreement for a notional amount of $21.3 million, with a fixed price floor of R$3.10 and a fixed price ceiling of R$3.40, to manage a portion of its foreign currency risk. The collar agreement settled on February 3, 2003, at a favorable settlement amount of approximately $760,000 (pretax). Gains or losses on this derivative instrument are recorded in earnings each period. The fair value of the foreign currency collar agreement at December 31, 2002, was approximately $903,000 ($566,000 after tax). From time to time, derivative instruments may be utilized to manage a portion of the foreign currency risk.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 41 through 79 of the Company's Annual Report, which is incorporated herein by reference.
ITEM 9.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is made to Pages 2 through 5 and 13 through 14 of the Company's Proxy Statement dated March 7, 2003 (Proxy Statement), which is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 6 through 9 and 16 of the Proxy Statement, which is incorporated herein by reference with the exception of the compensation committee report on executive compensation.
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, 2002 with respect to the Company's equity compensation plans. These plans include the 1992 Key Employee Stock Option Plan (KESOP), the 1997 Non-Employee Director Long-Term Incentive Plan (1997 Director Plan), the 1997 Executive Long-Term Incentive Plan (1997 LTIP), the Non-Employee Director Stock Compensation Plan (Director Compensation Plan), the 1998 Option Award Program (All Employee Plan) and the Group Genius Innovation Plan (Group Genius Plan).
(c) Number of securities (a) remaining Number of (b) available for securities to Weighted- future issuance be issued upon average under equity exercise of exercise price compensation outstanding of outstanding plans (excluding options, options, securities warrants and warrants and reflected in Plan Category rights rights column (a))
Equity compensation plans approved by stockholders (1) 2,170,595 $27.49 4,510,084 (2)(3)
Equity compensation plans not approved by stockholders (4) 1,070,250 $28.62 774,870 (5)
Total 3,240,845 $27.87 5,284,954
(1) Consists of the KESOP, the 1997 Director Plan, the 1997 LTIP and the Director Compensation Plan.
(2) In addition to being available for future issuance upon exercise of options, 153,000 shares under the 1997 Director Plan may instead be issued in connection with stock appreciation rights, restricted stock, performance units, performance shares or other equity-based awards, and 4,311,628 shares under the Company's 1997 LTIP may instead be issued in connection with stock appreciation rights, restricted stock, performance units, performance shares or other equity-based awards.
(3) This amount also includes 45,456 shares available for issuance under the Director Compensation Plan. Under the Director Compensation Plan, in addition to a cash retainer, non-employee directors are awarded 1,000 shares following the date of the Company's annual meeting of stockholders. Additionally, a non- employee director may acquire additional shares under the Director Compensation Plan in lieu of receiving the cash portion of the director's retainer or fees.
(4) Consists of the All Employee Plan and the Group Genius Plan.
(5) In addition to being available for future issuance upon exercise of options, 99,600 shares under the Group Genius 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 two equity compensation plans have not been approved by the Company's stockholders.
The All Employee Plan
The All Employee Plan 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 1,875,000. 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, 150 options (adjusted for the three-for-two stock split in July 1998) were granted to each of approximately 2,200 employees. No officers received grants. These options vested on March 2, 2001. In 2001, 200 options were granted to each of approximately 5,900 employees. No officers received grants. These options will vest on February 13, 2004. As of December 31, 2002, options covering 1,070,250 shares of common stock were outstanding under the plan. 675,270 shares remained available for future grant and options covering 129,480 shares had been exercised.
The Group Genius Plan
The Group Genius 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 100,000. Shares granted under the plan may be authorized but unissued shares, treasury shares or shares purchased on the open market. Restricted stock- holders 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. In March 2002, 100 shares of stock were granted to each of three employees and 50 shares of stock were granted to each of two employees.
Reference is made to Pages 15 and 16 of the Proxy Statement, which is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14.
ITEM 14. 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-14(c) and 15d-14(c) of the Securities Exchange Act of 1934 (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 under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Company's chief executive officer and chief financial officer have evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days before the filing of this Annual Report on Form 10-K (Evaluation Date), and, they have concluded that, as of the Evaluation Date, such controls and procedures were effective to accomplish those tasks.
Changes in internal controls
The Company maintains a system of internal accounting controls that are 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 significant changes in the Company's internal controls or in other factors that could significantly affect the Company's internal controls subsequent to the Evaluation Date, nor were there any significant deficiencies or material weaknesses in the Company's internal controls.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements, Financial Statement Schedules and Exhibits
Index to Financial Statements and Financial Statement Schedules Page 1. Financial Statements:
Independent Auditors' Report for the year ended December 31, 2002 * Report of Independent Public Accountants for the years ended December 31, 2001 and 2000 * Consolidated Statements of Income for each of the three years in the period ended December 31, 2002 * Consolidated Balance Sheets at December 31, 2002 and 2001 * Consolidated Statements of Common Stockholders' Equity for each of the three years in the period ended December 31, 2002 * Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2002 * Notes to Consolidated Financial Statements *
2. Financial Statement Schedules:
Independent Auditors' Report on Financial Statement Schedule for the year ended December 31, 2002 ** Report of Independent Public Accountants on Financial Statement Schedule for the years ended December 31, 2001 and 2000 ** Schedule II - Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2002, 2001 and 2000 **
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. _________________________
* The Consolidated Financial Statements listed in the above index which are included in the Company's Annual Report to Stockholders for 2002 are hereby incorporated by reference. With the exception of the pages referred to in Items 6 and 8, the Company's Annual Report to Stockholders for 2002 is not to be deemed filed as part of this report. ** Filed herewith.
3. Exhibits: 3(a) Restated Certificate of Incorporation of the Company, as amended, filed as Exhibit 3(a) to Form 10-Q for the quarter ended June 30, 2002, in File No. 1-3480 * 3(b) By-laws of the Company, as amended, filed as Exhibit 4(b) to Form S-8 on October 1, 2001, in Registration No. 333-70622 * 3(c) Certificate of Designations of Series B Preference Stock of the Company, as amended, filed as Exhibit 3(a) to Form 10-Q for the quarter ended September 30, 2002, 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 Forty-Ninth 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) in Registration No. 33-66682; and Exhibits 4(e), 4(f) and 4(g) in Registration No. 33-53896; and Exhibit 4(c)(i) in Registration No. 333-49472 * 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 * + 10(a) Executive Incentive Compensation Plan, as amended, filed as Exhibit 10(a) to Form 10-K for the year ended December 31, 2001, in File No. 1-3480 * + 10(b) 1992 Key Employee Stock Option Plan, as amended ** + 10(c) Supplemental Income Security Plan, as amended ** + 10(d) Directors' Compensation Policy, as amended, filed as Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 2002, in File No. 1-3480 * + 10(e) Deferred Compensation Plan for Directors, as amended ** + 10(f) Non-Employee Director Stock Compensation Plan, as amended, filed as Exhibit 10(f) to Form 10-K for the year ended December 31, 2001, in File No. 1-3480 * + 10(g) 1997 Non-Employee Director Long-Term Incentive Plan, as amended, filed as Exhibit 10(d) to Form 10-Q for the quarter ended June 30, 2000, in File No. 1-3480 * + 10(h) 1997 Executive Long-Term Incentive Plan, as amended, filed as Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 2001, in File No. 1-3480 * + 10(i) Change of Control Employment Agreement between the Company and John K. Castleberry, filed as Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(j) Change of Control Employment Agreement between the Company and Cathleen M. Christopherson, filed as Exhibit 10(b) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(k) Change of Control Employment Agreement between the Company and Richard A. Espeland, filed as Exhibit 10(c) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(l) Change of Control Employment Agreement between the Company and Terry D. Hildestad, filed as Exhibit 10(d) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(m) Change of Control Employment Agreement between the Company and Lester H. Loble, II, filed as Exhibit 10(e) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(n) Change of Control Employment Agreement between the Company and Vernon A. Raile, filed as Exhibit 10(f) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(o) Change of Control Employment Agreement between the Company and Warren L. Robinson, filed as Exhibit 10(g) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(p) Change of Control Employment Agreement between the Company and William E. Schneider, filed as Exhibit 10(h) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(q) Change of Control Employment Agreement between the Company and Ronald D. Tipton, filed as Exhibit 10(i) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(r) Change of Control Employment Agreement between the Company and Martin A. White, filed as Exhibit 10(j) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(s) Change of Control Employment Agreement between the Company and Robert E. Wood, filed as Exhibit 10(k) to Form 10-Q for the quarter ended September 30, 2002, in File No. 1-3480 * + 10(t) Separation Agreement and Release between the Company and Douglas C. Kane ** + 10(u) 1998 Option Award Program ** + 10(v) Group Genius Innovation Plan ** 12 Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends ** 13 Selected financial data, financial statements and supplementary data as contained in the Annual Report to Stockholders for 2002; Independent Auditors' Report on Financial Statement Schedule for the year ended December 31, 2002; Report of Independent Public Accountants on Financial Statement Schedule for the years ended December 31, 2001 and 2000; and Financial Statement Schedule II ** 21 Subsidiaries of MDU Resources Group, Inc. ** 23 Consent of Independent Auditors ** 99 Statement Furnished Pursuant to Section 906 of Sarbanes - Oxley Act of 2002 ** ________________________ * Incorporated herein by reference as indicated. ** Filed herewith. + Management contract, compensatory plan or arrangement required to be filed as an exhibit to this form pursuant to Item 15(c) of this report.
(b) Reports on Form 8-K
Form 8-K was filed on October 23, 2002. Under Item 5 -- Other Events, the Company reported the press release issued October 22, 2002, regarding earnings for the quarter ended September 30, 2002.
Form 8-K was filed on November 5, 2002. Under Item 5 -- Other Events and Item 7 -- Financial Statements and Exhibits, the Company reported the purchase of 213-megawatts of natural gas-fired electric generating facilities.
Form 8-K was filed on November 18, 2002. Under Item 7 -- Financial Statements and Exhibits, the Company filed an Underwriting Agreement relating to a public offering of the Company's common stock.
Form 8-K was filed on December 23, 2002. Under Item 5 -- Other Events and Item 7 -- Financial Statements and Exhibits, the Company reported the purchase of a 66.6-megawatt wind- powered electric generation facility.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, 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 28, 2003 By: /s/ Martin A. White Martin A. White (Chairman of the Board, President and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, 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/ Martin A. White Chief Executive February 28, 2003 Martin A. White (Chairman of the Board, Officer President and Chief Executive Officer) and Director
/s/ Warren L. Robinson Chief Financial February 28, 2003 Warren L. Robinson (Executive Vice Officer President, Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting February 28, 2003 Vernon A. Raile (Senior Vice President, Officer Controller and Chief Accounting Officer)
/s/ Harry J. Pearce Lead Director February 28, 2003 Harry J. Pearce
Director Bruce R. Albertson
/s/ Thomas Everist Director February 28, 2003 Thomas Everist
/s/ Dennis W. Johnson Director February 28, 2003 Dennis W. Johnson
/s/ Robert L. Nance Director February 28, 2003 Robert L. Nance
/s/ John L. Olson Director February 28, 2003 John L. Olson
/s/ Homer A. Scott, Jr. Director February 28, 2003 Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director February 28, 2003 Joseph T. Simmons
/s/ Sister Thomas Welder Director February 28, 2003 Sister Thomas Welder
10-K CERTIFICATION
I, Martin A. White, certify that:
1. I have reviewed this annual report on Form 10-K of MDU Resources Group, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 28, 2003 /s/ Martin A. White Martin A. White Chairman of the Board, President and Chief Executive Officer
10-K CERTIFICATION
I, Warren L. Robinson, certify that:
1. I have reviewed this annual report on Form 10-K of MDU Resources Group, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: February 28, 2003 /s/ Warren L. Robinson Warren L. Robinson Executive Vice President, Treasurer and Chief Financial Officer