UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes X. No.
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Exchange Act). Yes X. No
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of May 9, 2003: 74,233,513
shares.
INTRODUCTION
This Form 10-Q contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements should be read with the cautionary
statements and important factors included in this Form 10-Q at Item
2 -- Management's Discussion and Analysis of Financial Condition and
Results of Operations - Risk Factors and Cautionary Statements that
May Affect Future Results. Forward-looking statements are all
statements other than statements of historical fact, including
without limitation, those statements that are identified by the
words "anticipates," "estimates," "expects," "intends," "plans,"
"predicts" and similar expressions.
MDU Resources Group, Inc. (Company) is a diversified natural
resource company which was incorporated under the laws of the state
of Delaware in 1924. Its principal executive offices are at the
Schuchart Building, 918 East Divide Avenue, P.O. Box 5650, Bismarck,
North Dakota 58506-5650, telephone (701) 222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), a public utility
division of the Company, through the electric and natural gas
distribution segments, generates, transmits and distributes
electricity and distributes natural gas in the northern Great
Plains. Great Plains Natural Gas Co. (Great Plains), another public
utility division of the Company, distributes natural gas in
southeastern North Dakota and western Minnesota. These operations
also supply related value-added products and services in the
northern Great Plains.
The Company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI
Holdings), Knife River Corporation (Knife River), Utility Services,
Inc. (Utility Services), Centennial Energy Resources LLC (Centennial
Resources) and Centennial Holdings Capital LLC (Centennial Capital).
WBI Holdings is comprised of the pipeline and energy
services and the natural gas and oil production segments.
The pipeline and energy services segment provides natural
gas transportation, underground storage and gathering
services through regulated and nonregulated pipeline
systems primarily in the Rocky Mountain and northern Great
Plains regions of the United States. The pipeline and
energy services segment also provides energy-related
management services, including cable and pipeline
magnetization and locating. The natural gas and oil
production segment is engaged in natural gas and oil
acquisition, exploration and production activities
primarily in the Rocky Mountain region of the United States
and in the Gulf of Mexico.
Knife River mines aggregates and markets crushed stone,
sand, gravel and other related construction materials,
including ready-mixed concrete, cement, asphalt and other
value-added products, as well as performing integrated
construction services, in the north central and western
United States, including Alaska and Hawaii.
Utility Services is a diversified infrastructure company
specializing in electric, gas and telecommunication utility
construction, as well as industrial and commercial
electrical, exterior lighting and traffic signalization
throughout most of the United States. Utility Services also
provides related specialty equipment manufacturing, sales
and rental services.
Centennial Resources owns electric generating facilities in
the United States. Electric capacity and energy produced at
these facilities is sold under long-term contracts to
nonaffiliated entities. Centennial Resources also invests
in potential new growth opportunities that are not directly
being pursued by the other business units. These activities
are reflected in the independent power production segment.
Centennial Capital insures and reinsures various types of
risks as a captive insurer for certain of the Company's
subsidiaries. The function of the captive program is to
fund the deductible layers of the insured companies' general
liability and automobile liability coverages. Centennial
Capital also owns certain real and personal property and
contract rights. These activities are reflected in the
independent power production segment.
The Company, through its wholly owned subsidiary, Centennial
Energy Resources International Inc (Centennial International), has
an investment in an electric generating facility in Brazil.
Electric capacity and energy produced at this facility is sold
under a long-term contract to a nonaffiliated entity. Centennial
International invests in projects outside the United States which
are consistent with the Company's philosophy, growth strategy and
areas of expertise. These activities are reflected in the
independent power production segment.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three Months Ended March 31, 2003 and 2002
Consolidated Balance Sheets --
March 31, 2003 and 2002, and December 31, 2002
Consolidated Statements of Cash Flows --
Three Months Ended March 31, 2003 and 2002
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Part II -- Other Information
Signatures
Form 10-Q Certifications
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
2003 2002
(In thousands, except
per share amounts)
Operating revenues $467,753 $381,935
Operating expenses:
Fuel and purchased power 15,407 13,944
Purchased natural gas sold 76,106 35,695
Operation and maintenance 259,545 235,514
Depreciation, depletion and amortization 44,065 36,103
Taxes, other than income 19,683 14,882
414,806 336,138
Operating income 52,947 45,797
Other income -- net 3,685 3,591
Interest expense 12,859 10,546
Income before income taxes 43,773 38,842
Income taxes 16,076 15,120
Income before cumulative effect of accounting change 27,697 23,722
Cumulative effect of accounting change (Note 8) (7,589) ---
Net income 20,108 23,722
Dividends on preferred stocks 187 189
Earnings on common stock $ 19,921 $ 23,533
Earnings per common share -- basic:
Earnings before cumulative effect of
accounting change $ .37 $ .34
Cumulative effect of accounting change (.10) ---
Earnings per common share -- basic $ .27 $ .34
Earnings per common share -- diluted:
Earnings before cumulative effect of
accounting change $ .37 $ .34
Cumulative effect of accounting change (.10) ---
Earnings per common share -- diluted $ .27 $ .34
Dividends per common share $ .24 $ .23
Weighted average common shares outstanding -- basic 73,546 69,469
Weighted average common shares outstanding -- diluted 74,063 70,013
Pro forma amounts assuming retroactive
application of accounting change:
Net income $ 27,697 $ 23,126
Earnings per common share -- basic $ .37 $ .33
Earnings per common share -- diluted $ .37 $ .33
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, March 31, December 31,
2003 2002 2002
(In thousands, except shares
and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 75,843 $ 50,082 $ 67,556
Receivables, net 312,472 248,876 325,395
Inventories 89,893 73,494 93,123
Deferred income taxes 11,205 19,087 8,877
Prepayments and other current assets 42,424 51,534 42,597
531,837 443,073 537,548
Investments 42,777 38,184 42,864
Property, plant and equipment 3,169,926 2,720,846 3,003,996
Less accumulated depreciation,
depletion and amortization 1,125,777 975,218 1,079,110
2,044,149 1,745,628 1,924,886
Deferred charges and other assets:
Goodwill 190,908 176,003 190,999
Other intangible assets, net 185,273 165,902 176,164
Other 63,198 64,063 64,788
439,379 405,968 431,951
$3,058,142 $2,632,853 $2,937,249
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 12,500 $ --- $ 20,000
Long-term debt and preferred
stock due within one year 22,947 10,732 22,183
Accounts payable 137,370 100,615 132,120
Taxes payable 23,936 20,545 13,108
Dividends payable 17,971 16,375 17,959
Other accrued liabilities 108,620 93,094 94,275
323,344 241,361 299,645
Long-term debt 895,505 764,544 819,558
Deferred credits and other liabilities:
Deferred income taxes 369,010 349,571 374,097
Other liabilities 170,695 129,357 144,004
539,705 478,928 518,101
Preferred stock subject to mandatory
redemption 1,200 1,300 1,200
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Shares issued --
$1.00 par value, 74,337,088 at
March 31, 2003, 70,616,838 at
March 31, 2002 and 74,282,038 at
December 31, 2002) 74,337 70,617 74,282
Other paid-in capital 750,244 662,613 748,095
Retained earnings 476,935 401,988 474,798
Accumulated other comprehensive
income (loss) (14,502) 128 (9,804)
Treasury stock at cost - 239,521
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 1,283,388 1,131,720 1,283,745
Total stockholders' equity 1,298,388 1,146,720 1,298,745
$3,058,142 $2,632,853 $2,937,249
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2003 2002
(In thousands)
Operating activities:
Net income $ 20,108 $ 23,722
Cumulative effect of accounting change 7,589 ---
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 44,065 36,103
Deferred income taxes and investment tax credit 988 1,959
Changes in current assets and liabilities, net
of acquisitions:
Receivables 14,411 36,483
Inventories 3,826 21,847
Other current assets (5,187) (14,678)
Accounts payable (657) (9,566)
Other current liabilities 19,839 6,276
Other noncurrent changes 5,081 1,617
Net cash provided by operating activities 110,063 103,763
Investing activities:
Capital expenditures (63,735) (55,002)
Acquisitions, net of cash acquired (100,842) (10,413)
Net proceeds from sale or disposition of property 3,644 1,817
Investments 87 14
Proceeds from notes receivable 7,812 4,000
Net cash used in investing activities (153,034) (59,584)
Financing activities:
Net change in short-term borrowings (7,500) ---
Issuance of long-term debt 89,000 2,200
Repayment of long-term debt (12,290) (21,819)
Proceeds from issuance of common stock, net 19 86
Dividends paid (17,971) (16,375)
Net cash provided by (used in) financing activities 51,258 (35,908)
Increase in cash and cash equivalents 8,287 8,271
Cash and cash equivalents -- beginning of year 67,556 41,811
Cash and cash equivalents -- end of period $ 75,843 $ 50,082
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
March 31, 2003 and 2002
(Unaudited)
1. Basis of presentation
The accompanying consolidated interim financial statements
were prepared in conformity with the basis of presentation
reflected in the consolidated financial statements included in
the Annual Report to Stockholders for the year ended
December 31, 2002 (2002 Annual Report), and the standards of
accounting measurement set forth in Accounting Principles Board
(APB) Opinion No. 28 and any amendments thereto adopted by the
Financial Accounting Standards Board (FASB). Interim financial
statements do not include all disclosures provided in annual
financial statements and, accordingly, these financial
statements should be read in conjunction with those appearing
in the Company's 2002 Annual Report. The information is
unaudited but includes all adjustments which are, in the
opinion of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results for particular segments, and for the
Company as a whole, may not be indicative of results for the
full fiscal year.
3. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of
March 31, 2003 and 2002, and December 31, 2002, was $8.5
million, $5.7 million and $8.2 million, respectively.
4. Earnings per common share
Basic earnings per common share were computed by dividing
earnings on common stock by the weighted average number of
shares of common stock outstanding during the year. Diluted
earnings per common share were computed by dividing earnings on
common stock by the total of the weighted average number of
shares of common stock outstanding during the year, plus the
effect of outstanding stock options, restricted stock grants
and performance share awards. For the three months ended
March 31, 2003 and 2002, 2,381,180 shares and 2,572,850 shares,
respectively, with an average exercise price of $30.11 and
$30.15, respectively, attributable to outstanding stock
options, were excluded from the calculation of diluted earnings
per share because their effect was antidilutive. Common stock
outstanding includes issued shares less shares held in
treasury.
5. Stock-based compensation
The Company has stock option plans for directors, key
employees and employees and accounts for these option plans in
accordance with APB Opinion No. 25 under which no compensation
cost has been recognized.
The following table illustrates the effect on earnings and
earnings per common share as if the Company had applied
Statement of Financial Accounting Standards (SFAS) No. 123,
"Accounting for Stock-Based Compensation" to its stock-based
compensation:
Three Months Ended
March 31,
2003 2002
(In thousands, except
per share amounts)
Earnings on common stock, as reported $ 19,921 $23,533
Total stock-based compensation
expense determined under fair value
method for all awards, net of related
tax effects (590) (688)
Pro forma earnings on common stock $ 19,331 $22,845
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect of
accounting change $ .37 $ .34
Cumulative effect of accounting change (.10) ---
Earnings per common share -- basic $ .27 $ .34
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect of
accounting change $ .36 $ .33
Cumulative effect of accounting change (.10) ---
Earnings per common share -- basic $ .26 $ .33
Three Months Ended
March 31,
2003 2002
(In thousands, except
per share amounts)
Earnings per common share -- diluted --
as reported:
Earnings before cumulative effect of
accounting change $ .37 $ .34
Cumulative effect of accounting change (.10) ---
Earnings per common share -- diluted $ .27 $ .34
Earnings per common share -- diluted --
pro forma:
Earnings before cumulative effect of
accounting change $ .36 $ .33
Cumulative effect of accounting change (.10) ---
Earnings per common share -- diluted $ .26 $ .33
6. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Three Months Ended
March 31,
2003 2002
(In thousands)
Interest, net of amount capitalized $ 8,667 $ 6,755
Income taxes $ 563 $ 1,824
7. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior period to conform to the current
presentation. Such reclassifications had no effect on net
income or stockholders' equity as previously reported.
8. New accounting standards
In June 2001, the FASB approved SFAS No. 143, "Accounting
for Asset Retirement Obligations." SFAS No. 143 requires
entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred.
When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted
to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the
obligation for the recorded amount or incurs a gain or loss
upon settlement. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. For more information on the
adoption of SFAS No. 143, see Note 13.
In April 2002, the FASB approved SFAS No. 145, "Rescission
of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13, and Technical Corrections." FASB No. 4
required all gains or losses from extinguishment of debt to be
classified as extraordinary items net of income taxes. SFAS
No. 145 requires that gains and losses from extinguishment of
debt be evaluated under the provisions of APB Opinion No. 30,
and be classified as ordinary items unless they are unusual or
infrequent or meet the specific criteria for treatment as an
extraordinary item. SFAS No. 145 is effective for fiscal years
beginning after May 15, 2002. The adoption of SFAS No. 145 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" (FIN 45). FIN 45 clarifies the disclosures to be made
by a guarantor in its interim and annual financial statements
about its obligations under certain guarantees that it has
issued. FIN 45 also requires a guarantor to recognize, at the
inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing certain types of guarantees.
Certain types of guarantees are not subject to the initial
recognition and measurement provisions of FIN 45 but are
subject to its disclosure requirements. The initial
recognition and initial measurement provisions of FIN 45 are
applicable on a prospective basis to guarantees issued or
modified after December 31, 2002, regardless of the guarantor's
fiscal year-end. The guarantor's previous accounting for
guarantees issued prior to the date of the initial application
of FIN 45 shall not be revised or restated. The disclosure
requirements in FIN 45 are effective for financial statements
of interim or annual periods ended after December 15, 2002.
The Company will apply the initial recognition and initial
measurement provisions of FIN 45 to guarantees issued or
modified after December 31, 2002. For more information on the
Company's guarantees and the disclosure requirements of FIN 45,
as applicable to the Company, see Note 18.
In January 2003, the FASB issued FASB Interpretation
No. 46, "Consolidation of Variable Interest Entities" (FIN 46).
FIN 46 clarifies the application of Accounting Research
Bulletin No. 51, "Consolidated Financial Statements" to certain
entities in which equity investors do not have the
characteristics of a controlling financial interest or do not
have sufficient equity at risk for the entity to finance its
activities without additional subordinated support from other
parties. FIN 46 requires existing unconsolidated variable
interest entities to be consolidated by their primary
beneficiaries if the entities do not effectively disperse risks
among parties involved. All companies with variable interests
in variable interest entities created after January 31, 2003,
shall apply the provisions of FIN 46 to those entities
immediately. FIN 46 is effective for the first fiscal year or
interim period beginning after June 15, 2003, for variable
interest entities created before February 1, 2003. The Company
will prospectively apply the provisions of FIN 46 that were
effective January 31, 2003. The Company is currently
evaluating the provisions of FIN 46 which are effective for the
first fiscal year or interim period beginning after June 15,
2003.
9. Comprehensive income
Comprehensive income is the sum of net income as reported
and other comprehensive income (loss). The Company's other
comprehensive loss resulted from losses on derivative
instruments qualifying as hedges and a foreign currency
translation adjustment.
The Company's comprehensive income, and the components of
other comprehensive loss, and their related tax effects, were
as follows:
Three Months Ended
March 31,
2003 2002
(In thousands)
Net income $ 20,108 $ 23,722
Other comprehensive loss --
Net unrealized loss on derivative
instruments qualifying as hedges:
Net unrealized loss on derivative
instruments arising during the
period, net of tax of $3,541 and
$838 in 2003 and 2002, respectively (5,538) (1,283)
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $716 and $527 in
2003 and 2002, respectively (1,120) 807
Net unrealized loss on derivative
instruments qualifying as hedges (4,418) (2,090)
Foreign currency translation adjustment (280) ---
(4,698) (2,090)
Comprehensive income $ 15,410 $ 21,632
10. Equity method investment
In August 2001, MDU Brasil Ltda. (MDU Brasil), an indirect
wholly owned Brazilian subsidiary of the Company, entered into
a joint venture agreement with a Brazilian firm under which the
parties have formed MPX Holdings, Ltda. (MPX). MDU Brasil has
a 49 percent interest in MPX. MPX, through a wholly owned
subsidiary, owns a 220-megawatt natural gas-fired power plant
(Project) in the Brazilian state of Ceara. Petrobras, the
partially Brazilian state-owned energy company, has agreed to
purchase all of the capacity and market all of the Project's
energy. The power purchase agreement with Petrobras expires in
May 2008 and is renewable for an additional 13 years. The
functional currency for the Project is the Brazilian real. The
power purchase agreement with Petrobras contains an embedded
derivative, which derives its value from an annual adjustment
factor, which largely indexes the contract capacity payments to
the U.S. dollar. For the three months ended March 31, 2003,
the Company's 49 percent share of the loss from the embedded
derivative in the power purchase agreement was $1.5 million
(after tax). In addition, the Company's 49 percent share of
the foreign currency gains resulting from revaluation of the
Brazilian real totaled $902,000 (after tax) for the three
months ended March 31, 2003.
The Company's investment in the Project has been accounted
for under the equity method of accounting, and the Company's
share of net income, including the previously mentioned foreign
currency gain and loss from the embedded derivative in the
power purchase agreement, for the three months ended March 31,
2003, of $495,000 was included in other income - net. At March
31, 2003 and 2002, and December 31, 2002, the Company's
investment in the Project was approximately $20.5 million,
$23.8 million and $27.8 million, respectively. The investment
in the Project decreased from December 31, 2002, to March 31,
2003, due to the repayment of a portion of certain obligations
by MPX.
11. Goodwill and other intangible assets
The changes in the carrying amount of goodwill by business
segment were as follows:
Net
Goodwill
Acquired
Balance and Other Balance
as of Changes as of
Three Months January 1, During March 31,
Ended March 31, 2003 2003 the Year* 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 83 62,570
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 (174) 111,713
Independent power
production 7,131 --- 7,131
Total $ 190,999 $ (91) $ 190,908
Net
Goodwill
Acquired
Balance and Other Balance
as of Changes as of
Three Months January 1, During March 31,
Ended March 31, 2002 2002 the Year* 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 (652) 61,257
Pipeline and energy
services 9,336 --- 9,336
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 2,658 105,410
Independent power
production --- --- ---
Total $ 173,997 $ 2,006 $ 176,003
Net
Goodwill
Acquired
Balance and Other Balance
as of Changes as of
Year Ended January 1, During December 31,
December 31, 2002 2002 the Year* 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 578 62,487
Pipeline and energy
services 9,336 158 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 9,135 111,887
Independent power
production --- 7,131 7,131
Total $ 173,997 $ 17,002 $ 190,999
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
Other intangible assets were as follows:
March 31, March 31, December 31,
2003 2002 2002
(In thousands)
Amortizable intangible
assets:
Leasehold rights $172,464 $166,696 $172,496
Accumulated amortization (8,274) (5,080) (7,494)
164,190 161,616 165,002
Noncompete agreements 12,075 11,509 12,075
Accumulated amortization (9,477) (8,419) (9,366)
2,598 3,090 2,709
Other 17,733 1,388 7,224
Accumulated amortization (713) (192) (374)
17,020 1,196 6,850
Unamortizable intangible
assets 1,465 --- 1,603
Total $185,273 $165,902 $176,164
The unamortizable intangible assets were recognized in
accordance with SFAS No. 87, "Employers' Accounting for
Pensions" which requires that if an additional minimum
liability is recognized an equal amount shall be recognized as
an intangible asset, provided that the asset recognized shall
not exceed the amount of unrecognized prior service cost. The
unamortizable intangible asset will be eliminated or adjusted
as necessary upon a new determination of the amount of
additional liability.
Amortization expense for amortizable intangible assets for
the three months ended March 31, 2003 and 2002, and for the
year ended December 31, 2002, was $1.2 million, $231,000 and
$3.4 million, respectively. Estimated amortization expense for
amortizable intangible assets is $5.8 million in 2003, $5.7
million in 2004, $5.8 million in 2005, $4.6 million in 2006,
$4.6 million in 2007 and $158.5 million thereafter.
12. Derivative instruments
From time to time, the Company utilizes 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 following information
should be read in conjunction with Notes 1 and 5 in the
Company's Notes to Consolidated Financial Statements in the
2002 Annual Report.
As of March 31, 2003, a subsidiary of the Company held
derivative instruments designated as cash flow hedging
instruments.
Hedging activities
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.
For the three months ended March 31, 2003 and 2002, the
amount of hedge ineffectiveness recognized, which was included
in operating revenues, was immaterial. For the three months
ended March 31, 2003 and 2002, the subsidiary did not exclude
any components of the derivative instruments' gain or loss from
the assessment of hedge effectiveness and there were no
reclassifications into earnings as a result of the
discontinuance of hedges.
Gains and losses on derivative instruments that are
reclassified from accumulated other comprehensive income (loss)
to current-period earnings are included in the line item in
which the hedged item is recorded. As of March 31, 2003, the
maximum term of the subsidiary's swap and collar agreements, in
which the subsidiary of the Company is hedging its exposure to
the variability in future cash flows for forecasted
transactions, is nine months. The subsidiary of the Company
estimates that over the next nine months net losses of
approximately $9.0 million after tax will be reclassified from
accumulated other comprehensive loss into earnings, subject to
changes in natural gas and oil market prices, as the hedged
transactions affect earnings.
13. Asset retirement obligations
The Company adopted SFAS No. 143 on January 1, 2003. The
Company recorded obligations related to the plugging and
abandonment of natural gas and oil wells; decommissioning of
certain electric generating facilities; reclamation of certain
aggregate properties and certain other obligations associated
with leased properties. Removal costs associated with certain
natural gas distribution, transmission, storage and gathering
facilities have not been recognized as these facilities have
been determined to have indeterminate useful lives.
Upon adoption of SFAS No. 143, the Company recorded an
additional discounted liability of $22.5 million and a
regulatory asset of $493,000, increased net property, plant and
equipment by $9.6 million and recognized a one-time cumulative
effect charge of $7.6 million (net of deferred income tax
benefits of $4.8 million). The Company believes that any
expenses under SFAS No. 143 as they relate to regulated
operations will be recovered in rates over time and
accordingly, deferred such expenses as a regulatory asset upon
adoption. The Company will continue to defer those SFAS No.
143 expenses that it believes will be recovered in rates over
time. In addition to the $22.5 million liability recorded upon
the adoption of SFAS No. 143, the Company had previously
recorded a $7.5 million liability related to retirement
obligations.
A reconciliation of the Company's liability was as
follows:
For the Three
Months Ended
March 31, 2003
(In thousands)
January 1, 2003 $ 29,997
Liabilities incurred ---
Liabilities acquired 520
Liabilities settled (17)
Accretion expense 470
$ 30,970
This liability is included in other liabilities. If SFAS
No. 143 had been in effect during 2002, the Company's liability
would have been approximately $27.0 million and $27.5 million
at January 1, 2002, and March 31, 2002, respectively.
The fair value of assets that are legally restricted for
purposes of settling asset retirement obligations at March 31,
2003, was $5.1 million.
14. Common stock
At the Annual Meeting of Stockholders held on April 23,
2002, the Company's common stockholders approved an amendment
to the Certificate of Incorporation increasing the authorized
number of common shares from 150 million shares to 250 million
shares with a par value of $1.00 per share.
15. Business segment data
The Company's reportable segments are those that are based
on the Company's method of internal reporting, which generally
segregates the strategic business units due to differences in
products, services and regulation. 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.
The Company's operations are now conducted through seven
business segments and all prior period information has been
restated to reflect this change. The vast majority of the
Company's operations are located within the United States. The
Company also has investments in foreign countries, which
consists largely of an investment in a natural gas-fired
electric generation station in Brazil as discussed in Note 10.
The electric segment generates, transmits and distributes
electricity and the natural gas distribution segment
distributes natural gas. These operations also supply related
value-added products and services in the northern Great Plains.
The utility services segment consists of a diversified
infrastructure company specializing in electric, gas and
telecommunication utility construction, as well as industrial
and commercial electrical, exterior lighting and traffic
signalization throughout most of the United States. Utility
services also provides related specialty equipment
manufacturing, sales and rental services. The pipeline and
energy services segment provides natural gas transportation,
underground storage and gathering services through regulated
and nonregulated pipeline systems primarily in the Rocky
Mountain and northern Great Plains regions of the United
States. The pipeline and energy services segment also provides
energy-related management services, including cable and
pipeline magnetization and locating. The natural gas and oil
production segment is engaged in natural gas and oil
acquisition, exploration and production activities primarily in
the Rocky Mountain region of the United States and in the Gulf
of Mexico. The construction materials and mining segment mines
aggregates and markets crushed stone, sand, gravel and related
construction materials, including ready-mixed concrete, cement,
asphalt and other value-added products, as well as performing
integrated construction services, in the north central and
western United States, including Alaska and Hawaii. The
independent power production segment owns electric generating
facilities in the United States and Brazil. Electric capacity
and energy produced at these facilities is sold under long-term
contracts to nonaffiliated entities. This segment also invests
in potential new growth opportunities that are not directly
being pursued by other business segments.
Segment information follows the same accounting policies
as described in Note 1 of the Company's 2002 Annual Report.
Segment information was as follows:
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended March 31, 2003
Electric $ 45,671 $ --- $ 4,817
Natural gas distribution 110,987 --- 4,245
Utility services 103,663 --- 1,110
Pipeline and energy
services 39,212 21,919 4,311
Natural gas and oil
production 41,118 27,905 11,666
Construction materials
and mining 120,753 --- (7,440)
Independent power
production 6,349 740 1,212
Intersegment eliminations --- (50,564) ---
Total $ 467,753 $ --- $ 19,921
Three Months
Ended March 31, 2002
Electric $ 40,070 $ --- $ 3,491
Natural gas distribution 71,713 --- 4,517
Utility services 108,287 --- 1,349
Pipeline and energy
services 19,800 21,903 2,905
Natural gas and oil
production 48,733 13,674 21,070
Construction materials
and mining 93,332 --- (9,721)
Independent power
production --- 847 (78)
Intersegment eliminations --- (36,424) ---
Total $ 381,935 $ --- $ 23,533
16. Acquisitions
During the first three months of 2003, the Company
acquired a wind-powered electric generation facility in
California. The total purchase consideration for this business
and final adjustments with respect to certain other
acquisitions acquired in 2002, including the Company's common
stock and cash, was $102.0 million. For more information on
the wind-powered electric generation facility in California see
Items 1 and 2 - Business and Properties - Independent Power
Production (Other) in the Company's 2002 Form 10-K.
The above 2003 acquisition was accounted for under the
purchase method of accounting and accordingly, the acquired
assets and liabilities assumed have been preliminarily recorded
at their respective fair values as of the date of acquisition.
Final fair market values are pending the completion of the
review of the relevant assets, liabilities and issues identified
as of the acquisition date. The results of operations of the
acquired business are included in the financial statements since
the date of acquisition. Pro forma financial amounts reflecting
the effects of the above acquisition are not presented as such
acquisition was not material to the Company's financial
position, results of operations or cash flows.
17. Regulatory matters and revenues subject to refund
In December 2002, Montana-Dakota filed an application with
the South Dakota Public Utilities Commission (SDPUC) for a
natural gas rate increase. Montana-Dakota requested a total of
$2.2 million annually or 5.8 percent above current rates. A
final order from the SDPUC is due June 30, 2003.
In October 2002, Great Plains filed an application with
the Minnesota Public Utilities Commission (MPUC) for a natural
gas rate increase. Great Plains requested a total of $1.6
million annually or 6.9 percent above current rates. In
December 2002, the MPUC issued an Order setting interim rates
that approved an interim increase of $1.4 million annually
effective December 6, 2002. Great Plains began collecting such
rates effective December 6, 2002, subject to refund until the
MPUC issues a final order. A final order from the MPUC is due
August 22, 2003.
In May 2002, Montana-Dakota filed an application with the
Montana Public Service Commission (MTPSC) for a natural gas
rate increase. Montana-Dakota requested a total of $3.6
million annually or 6.5 percent above current rates. In
September 2002, the MTPSC approved an interim increase of $2.1
million annually, effective with service rendered on and after
September 5, 2002. Montana-Dakota began collecting such rates
effective September 5, 2002, which were subject to refund until
the MTPSC issued a final order. In November 2002, the MTPSC
approved an additional interim increase of $300,000 annually
effective November 15, 2002. The additional interim increase
was the result of a Stipulation reached between Montana-Dakota
and the Montana Consumer Counsel, the only intervener in the
proceeding. Under the terms of the Stipulation, the total
interim relief granted ($2.4 million) would be the final
increase in the proceeding. A hearing before the MTPSC was
held in December 2002, at which the MTPSC took under advisement
the Stipulation agreed upon by Montana-Dakota and the Montana
Consumer Counsel. On April 4, 2003, the MTPSC issued a Final
Order authorizing an increase of $2.4 million annually as
outlined in the Stipulation, effective with service rendered on
or after April 13, 2003.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund for certain of the
above proceedings. The Company believes that such reserves are
adequate based on its assessment of the ultimate outcome of the
proceedings.
In December 1999, Williston Basin Interstate Pipeline
Company (Williston Basin), an indirect wholly owned subsidiary
of the Company, filed a general natural gas rate change
application with the Federal Energy Regulatory Commission
(FERC). Williston Basin began collecting such rates effective
June 1, 2000, subject to refund. In May 2001, the
Administrative Law Judge (ALJ) issued an Initial Decision on
Williston Basin's natural gas rate change application. The
Initial Decision addressed numerous issues relating to the rate
change application, including matters relating to allowable
levels of rate base, return on common equity, and cost of
service; as well as volumes established for purposes of cost
recovery, and cost allocations and rate design. This matter is
currently pending before and subject to revision by the FERC.
The Company is not aware of the anticipated timing of the
review by the FERC of the ALJ's Initial Decision.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund with respect to
Williston Basin's pending regulatory proceeding. Williston
Basin believes that such reserves are adequate based on its
assessment of the ultimate outcome of the proceeding.
18. Contingencies
Litigation
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 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 in the discovery
stage. Grynberg has not specified the amount he seeks to
recover. Williston Basin and Montana-Dakota are unable to
estimate their potential exposure and will be unable to do so
until discovery is completed. Williston Basin and Montana-
Dakota believe that the Grynberg case will ultimately be
dismissed because Grynberg is not, as is required by the
Federal False Claims Act, the original source of the
information underlying the action. Failing this, Williston
Basin and Montana-Dakota believe Grynberg will not recover
damages from Williston Basin and Montana-Dakota because
insufficient facts exist to support the allegations. Williston
Basin and Montana-Dakota intend to vigorously contest this
suit.
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. The plaintiffs have not
specified the amount they seek to recover. Williston Basin
and Montana-Dakota are unable to estimate their potential
exposure and will be unable to do so until after the
discovery stage is complete. In September 2001, the
defendants in this suit filed a motion to dismiss, including
a request to dismiss for lack of personal jurisdiction, with
the State District Court. The motion to dismiss on grounds
other than lack of personal jurisdiction was denied by the
State District Court in August 2002. In January 2002, the
non-Kansas resident defendants in this suit filed a
supplemental motion to dismiss for lack of personal
jurisdiction with the State District Court. In September
2002, the plaintiffs moved for certification of the case as
a class action and on April 10, 2003, the State District
Court denied the motion. On April 22, 2003, the State
District Court stayed proceedings on all motions pending the
filing of a motion for leave to amend by the plaintiffs. On
May 12, 2003, the plaintiffs filed a motion to file an
amended class action petition. Neither Williston Basin nor
Montana-Dakota were named as defendants in the proposed
amended class action petition, which is currently pending.
Although Williston Basin's and Montana-Dakota's arguments
may be moot if the court grants plaintiffs' motion to file
an amended class action petition, they believe the Quinque
case will ultimately be dismissed as against them because
the court lacks personal jurisdiction over them. Failing
this, Williston Basin and Montana-Dakota believe the
plaintiffs will not recover damages from them because
insufficient facts exist to support their allegations.
Williston Basin and Montana-Dakota intend to vigorously
contest this suit.
The Company is also involved in other legal actions in the
ordinary course of its business. Although the outcomes of any
such legal actions cannot be predicted, management believes
that the outcomes with respect to these other legal proceedings
will not have a material adverse effect upon the Company's
financial position or results of operations.
Environmental matters
In December 2000, Morse Bros., Inc. (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, acquired by MBI in 1999, and part of
the Portland, Oregon, Harbor Superfund Site. Sixty-eight other
parties were also named in this administrative action. The EPA
wants responsible parties to share in the cleanup of sediment
contamination in the Willamette River. To date, costs of the
overall remedial investigation of the harbor site for both the
EPA and the Oregon State Department of Environmental Quality
(DEQ) are being recorded, and initially paid, through an
administrative consent order by the Lower Willamette Group
(LWG), a group of ten entities which does not include MBI. The
LWG estimates the overall remedial investigation and
feasibility study will cost approximately $10 million. It is
not possible to estimate the cost of a corrective action plan
until the remedial investigation and feasibility study has been
completed, the EPA has decided on a strategy, and a record of
decision has been published. While the remedial investigation
and feasibility study for the harbor site has commenced, it is
expected to take several years to complete. The development of
a proposed plan and record of decision on the harbor site is
not anticipated to occur until 2006, after which a cleanup plan
will be undertaken.
Based upon a review of the Portland Harbor sediment
contamination evaluation by the DEQ and other information
available, MBI does not believe it is a Responsible Party. In
addition, MBI has notified Georgia-Pacific West, Inc., the
seller of the commercial property site to MBI, that it intends
to seek indemnity for any and all liabilities incurred in
relation to the above matters, pursuant to the terms of their
sale agreement.
The Company believes it is not probable that it will incur
any material environmental remediation costs or damages in
relation to the above administrative action.
Guarantees
Centennial has unconditionally guaranteed a portion of
certain bank borrowings of MPX in connection with the Company's
equity method investment in the natural gas-fired electric
generation station in Brazil, as discussed in Note 10. The
Company, through MDU Brasil, owns 49 percent of MPX. At March
31, 2003, the aggregate amount of borrowings outstanding
subject to these guarantees was $64.7 million. The scheduled
repayment of these borrowings is $12.7 million in 2003, $8.7
million in 2004 and $43.3 million in 2006. In addition, the
related loan agreements provide that the guarantees with
respect to approximately $52 million will earlier terminate
upon MPX meeting certain financial covenants. The individual
investor, who through a Brazilian company owns 51 percent of
MPX, has also guaranteed a portion of these loans. Centennial
and the individual investor have entered into a reimbursement
agreement under which they have agreed to reimburse each other
to the extent they may be required to make any guarantee
payments in excess of their proportionate ownership share in
MPX. These guarantees are not reflected on the Consolidated
Balance Sheets.
In addition, Centennial has unconditionally guaranteed
borrowings under a $25 million credit agreement by a subsidiary
of the Company. The proceeds from these borrowings were used
in connection with the Company's investment in international
projects. The amount outstanding under this agreement at
March 31, 2003, was $12.5 million, which amount is reflected on
the Consolidated Balance Sheets. This subsidiary of the
Company is currently evaluating the renewal/extension of this
credit agreement, which expires June 30, 2003. In the event
this subsidiary of the Company defaults under its obligation,
Centennial would be required to make payments under its
guarantee.
In addition, WBI Holdings has guaranteed certain of its
subsidiary's natural gas and oil price swap and collar
agreement obligations. The amount of the subsidiary's
obligations at March 31, 2003, was $7.0 million. There is no
fixed maximum amount guaranteed in relation to the natural gas
and oil price swap and collar agreements; however, the amount
of hedging activity entered into by the subsidiary is limited
by corporate policy. The guarantees of the natural gas and oil
price swap and collar agreements at March 31, 2003, expire in
December 2003; however, the subsidiary continues to enter into
additional hedging activities, and, as a result, WBI Holdings
from time to time will issue additional guarantees on these
hedging obligations. The amounts outstanding under the natural
gas and oil price swap and collar agreements were reflected on
the Consolidated Balance Sheets. In the event the above
subsidiary defaults under its obligations, WBI Holdings would
be required to make payments under its guarantees.
Certain subsidiaries of the Company have outstanding
guarantees to third parties that guarantee the performance of
other subsidiaries of the Company that are related to natural
gas transportation and sales agreements, electric power supply
agreements and certain other guarantees. At March 31, 2003,
the fixed maximum amounts guaranteed under these agreements
aggregated $40.3 million. The amounts of scheduled expiration
of the maximum amounts guaranteed under these agreements
aggregate $10.1 million in 2003; $8.2 million in 2004; $5.0
million in 2005; $12.0 million in 2012; $2.0 million, which is
subject to expiration 30 days after the receipt of written
notice and $3.0 million, which has no scheduled maturity date.
In the event of default under these guarantee obligations, the
subsidiary issuing the guarantee for that particular obligation
would be required to make payments under its guarantee. The
amounts outstanding by subsidiaries of the Company under the
above guarantees was $795,000 and was reflected on the
Consolidated Balance Sheets at March 31, 2003.
WBI Holdings and Fidelity Exploration & Production Company
(Fidelity), an indirect wholly owned subsidiary of the Company,
have outstanding guarantees to Williston Basin Interstate
Pipeline Company, an indirect wholly owned subsidiary of the
Company. These guarantees are related to natural gas
transportation and storage agreements and guarantee the
performance of Prairielands Energy Marketing, Inc.
(Prairielands), an indirect wholly owned subsidiary of the
Company. At March 31, 2003, the fixed maximum amounts
guaranteed under these agreements aggregated $22.0 million.
Scheduled expiration of the maximum amounts guaranteed under
these agreements aggregate $2.0 million in 2005 and $20.0
million in 2009. In the event of Prairielands' default in its
payment obligations, the subsidiary issuing the guarantee for
its respective obligation would be required to make payments
under its guarantee. The amount outstanding by Prairielands
under the above guarantees was $744,000 and was reflected on
the Consolidated Balance Sheets at March 31, 2003.
In addition, Centennial has issued guarantees related to
the Company's purchase of maintenance items to third parties
for which no fixed maximum amounts have been specified. These
guarantees have no scheduled maturity date. In the event a
subsidiary of the Company defaults under its obligation in
relation to the purchase of certain maintenance items,
Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the
Company for maintenance were reflected on the Consolidated
Balance Sheets at March 31, 2003.
As of March 31, 2003, Centennial was contingently liable
for performance of certain of its subsidiaries under
approximately $232 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. The surety bonds
were not reflected on the Consolidated Balance Sheets.
ITEM 2. 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.
The Company's operations are now conducted through seven
business segments and all prior period information has been restated
to reflect this change. 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
opportunities that are not directly being pursued by other business
segments.
Reference should be made to 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.
Three Months
Ended
March 31,
2003 2002
Electric $ 4.8 $ 3.5
Natural gas distribution 4.2 4.5
Utility services 1.1 1.3
Pipeline and energy services 4.3 2.9
Natural gas and oil production 11.7 21.1
Construction materials and mining (7.4) (9.7)
Independent power production 1.2 (.1)
Earnings on common stock $ 19.9 $ 23.5
Earnings per common share - basic $ .27 $ .34
Earnings per common share - diluted $ .27 $ .34
Return on average common equity
for the 12 months ended 11.8% 13.7%
________________________________
Three Months Ended March 31, 2003 and 2002
Consolidated earnings for the quarter ended March 31, 2003,
decreased $3.6 million from the comparable period a year ago due to
lower earnings at the natural gas and oil production, natural gas
distribution and utility services businesses. Increased earnings at
the construction materials and mining, pipeline and energy services,
electric and independent power production businesses partially
offset the earnings decline.
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
Three Months
Ended
March 31,
2003 2002
Operating revenues:
Retail sales $ 37.2 $ 34.9
Sales for resale and other 8.5 5.2
45.7 40.1
Operating expenses:
Fuel and purchased power 15.4 13.9
Operation and maintenance 13.4 11.5
Depreciation, depletion and amortization 5.0 4.9
Taxes, other than income 2.0 2.0
35.8 32.3
Operating income $ 9.9 $ 7.8
Retail sales (million kWh) 600.1 558.8
Sales for resale (million kWh) 251.4 226.6
Average cost of fuel and purchased
power per kWh $ .017 $ .017
Natural Gas Distribution
Three Months
Ended
March 31,
2003 2002
Operating revenues:
Sales $ 110.0 $ 70.6
Transportation and other 1.0 1.1
111.0 71.7
Operating expenses:
Purchased natural gas sold 88.2 51.2
Operation and maintenance 11.6 9.5
Depreciation, depletion and amortization 2.5 2.4
Taxes, other than income 1.4 1.3
103.7 64.4
Operating income $ 7.3 $ 7.3
Volumes (MMdk):
Sales 17.5 16.6
Transportation 3.1 3.6
Total throughput 20.6 20.2
Degree days (% of normal)* 102% 99%
Average cost of natural gas, including
transportation thereon, per dk $ 5.05 $ 3.09
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Utility Services
Three Months
Ended
March 31,
2003 2002
Operating revenues $ 103.7 $ 108.3
Operating expenses:
Operation and maintenance 94.2 98.9
Depreciation, depletion and amortization 2.5 2.1
Taxes, other than income 4.4 4.2
101.1 105.2
Operating income $ 2.6 $ 3.1
Pipeline and Energy Services
Three Months
Ended
March 31,
2003 2002
Operating revenues:
Pipeline $ 25.4 $ 21.2
Energy services 35.7 20.5
61.1 41.7
Operating expenses:
Purchased natural gas sold 34.5 17.3
Operation and maintenance 12.3 12.8
Depreciation, depletion and amortization 3.7 3.6
Taxes, other than income 1.5 1.8
52.0 35.5
Operating income $ 9.1 $ 6.2
Transportation volumes (MMdk):
Montana-Dakota 8.4 7.8
Other 12.5 10.6
20.9 18.4
Gathering volumes (MMdk) 18.9 16.9
Natural Gas and Oil Production
Three Months
Ended
March 31,
2003 2002
Operating revenues:
Natural gas $ 55.2 $ 25.4
Oil 13.7 9.6
Other .1 27.4*
69.0 62.4
Operating expenses:
Operation and maintenance 16.4 13.5
Depreciation, depletion and amortization 14.2 11.6
Taxes, other than income 5.7 2.5
36.3 27.6
Operating income $ 32.7 $ 34.8
Production:
Natural gas (MMcf) 13,639 11,403
Oil (000's of barrels) 474 481
Average realized prices (including hedges):
Natural gas (per Mcf) $ 4.05 $ 2.23
Oil (per barrel) $ 29.00 $ 19.92
Average realized prices (excluding hedges):
Natural gas (per Mcf) $ 4.69 $ 2.15
Oil (per barrel) $ 31.05 $ 19.00
_____________________
* Includes the effects of a compromise agreement gain of $27.4
million ($16.6 million after tax).
Construction Materials and Mining
Three Months
Ended
March 31,
2003 2002
Operating revenues $ 120.8 $ 93.3
Operating expenses:
Operation and maintenance 111.5 91.8
Depreciation, depletion and amortization 14.6 11.4
Taxes, other than income 4.7 3.1
130.8 106.3
Operating loss $ (10.0) $ (13.0)
Sales (000's):
Aggregates (tons) 5,027 3,576
Asphalt (tons) 162 167
Ready-mixed concrete (cubic yards) 515 401
Independent Power Production
Three Months
Ended
March 31,
2003* 2002
Operating revenues $ 7.1 $ .8
Operating expenses:
Operation and maintenance 4.2 1.1
Depreciation, depletion and amortization 1.6 .1
5.8 1.2
Operating income (loss) $ 1.3 $ (.4)
Net generation capacity - kW 279,600 ---
Electricity produced and sold (thousand kWh) 48,900 ---
_____________________
* Reflects international operations for 2003 and domestic
operations acquired in November 2002 and January 2003.
NOTE: 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 intersegment transactions. The amounts
(dollars in millions) relating to the elimination of intersegment
transactions are as follows:
Three Months
Ended
March 31,
2003 2002
Operating revenues $ 50.6 $ 36.4
Purchased natural gas sold $ 46.6 $ 32.8
Operation and maintenance $ 4.0 $ 3.6
For further information on intersegment eliminations, see Note
15 of Notes to Consolidated Financial Statements.
Three Months Ended March 31, 2003 and 2002
Electric
Electric earnings increased as a result of higher sales for
resale revenues due to higher average realized sales for resale
prices, which were 54 percent higher than last year, and higher
sales for resale volumes, which were 11 percent higher than last
year, both resulting from stronger sales for resale markets. Higher
retail sales volumes, which were 7 percent higher than last year,
primarily to residential, commercial and large industrial customers,
also added to the increase in earnings. Partially offsetting the
earnings increase was higher operation and maintenance expense,
largely higher payroll costs.
Natural Gas Distribution
Earnings at the natural gas distribution business decreased as
a result of higher operation and maintenance expense, primarily
higher payroll costs, and decreased returns on natural gas held in
storage. Largely offsetting the earnings decline were higher
average realized retail sales prices, the result of rate increases
in Minnesota, Montana, North Dakota and Wyoming, and higher retail
sales volumes. Retail sales volumes were 6 percent higher than last
year due to weather that was 3 percent colder than the first quarter
of the prior year. The pass-through of higher natural gas prices
resulted in the increase in sales revenues and purchased natural gas
sold. For further information on the retail rate increases, see
Part I, Items 1 and 2 in the Company's Annual Report on Form 10-K
for the year ended December 31, 2002 and Note 17 of Notes to
Consolidated Financial Statements in this Form 10-Q.
Utility Services
Utility services earnings decreased as a result of lower
margins in the Central region, primarily the result of a slow down
in inside electrical work, along with lower margins in the Northwest
and Southwest regions due to decreased workloads, all reflections of
the soft economy. Partially offsetting the decline in earnings were
increased line construction workloads and margins in the Rocky
Mountain region and increased equipment sale margins.
Pipeline and Energy Services
Earnings at the pipeline and energy services business increased
as a result of higher transportation volumes of 14 percent,
increased gathering volumes of 11 percent and increased storage
revenues. The increase in energy services revenue and the related
increase in purchased natural gas sold were due to an increase in
natural gas prices since the comparable period last year.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due
to the 2002 compromise agreement gain of $27.4 million ($16.6
million after tax), included in 2002 operating revenues, and the
$12.7 million ($7.7 million after tax) noncash transition charge in
2003, reflecting the cumulative effect of an accounting change, as
discussed in Note 18 and Note 8 of Notes to Consolidated Financial
Statements, respectively. Also contributing 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, primarily higher lease
operating expenses resulting largely from the expansion of coalbed
natural gas production and higher general and administrative costs,
contributed to the decrease in earnings. Higher interest expense,
due primarily to higher average debt balances, also contributed to
the earnings decline. Partially offsetting the decrease in earnings
were higher realized natural gas prices of 82 percent, higher
natural gas production of 20 percent, largely from operated
properties in the Rocky Mountain area, and higher average realized
oil prices of 46 percent.
Construction Materials and Mining
The construction materials and mining business experienced
lower seasonal losses as a result of increased aggregate volumes and
margins and increased construction revenues, partially due to a
large harbor-deepening project in southern California, along with
higher ready-mixed concrete volumes, all at existing operations.
Partially offsetting the earnings improvement were higher
depreciation, depletion and amortization expense, partially due to
larger volumes produced, higher selling, general and administrative
costs, normal seasonal losses from businesses acquired since the
comparable period last year and higher fuel costs.
Independent Power Production
Earnings for the independent power production business
increased largely from domestic businesses acquired since the
comparable period last year, partially offset by higher interest
expense, resulting from higher average debt balances relating to
these acquisitions. The Brazilian operations also contributed to
the earnings increase. The Company's 49 percent share of net income
from its equity investment in Brazil of $495,000 (after tax) was due
to higher margins and foreign currency gains, partially offset by
plant financing costs and the mark-to-market loss on an embedded
derivative in the electric power contract.
Risk Factors and Cautionary Statements that May Affect Future
Results
The Company is including the following factors and cautionary
statements in this Form 10-Q 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. Nonetheless, the Company's expectations, beliefs or
projections may not 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.
Economic Risks
The recent events leading to the current adverse economic
environment may have a general negative impact on the Company's
future revenues and may result in a goodwill impairment for
Innovatum, Inc., an indirect wholly owned subsidiary of the Company.
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 and other large enterprises, the financial markets have
been highly volatile. An adverse economy could negatively affect
the level of governmental expenditures on public projects and the
timing of these projects which, 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 that specializes 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 March 31, 2003, 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, rapid changes in technology, competitors and
potential new customers.
The Company relies on financing sources and capital markets. The
Company's inability to access financing may impair its ability to
execute the Company's business plans, make capital expenditures or
pursue acquisitions that the Company 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 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 the Company's credit ratings
may increase the cost of borrowing or adversely affect its ability
to access one or more financial markets. Such disruptions could
include:
- A severe economic downturn
- The bankruptcy of unrelated companies in the same line of
business
- Capital market conditions generally
- Volatility in commodity prices
- Terrorist attacks
- Global events
The Company's natural gas and oil production business is dependent
on factors including commodity prices which 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.
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive
environmental laws and regulations that may increase its costs of
operations, impact or limit its business plans, or expose the
Company to environmental liabilities. One of the Company's
subsidiaries has been sued in connection with its coalbed natural
gas development activities.
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.
Existing environmental regulations may be revised and new
regulations seeking to protect the environment may be adopted or
become applicable to the Company. Revised or additional
regulations, which result in increased compliance costs or
additional operating restrictions, particularly if those costs are
not fully recoverable from customers, could have a material 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. If the plaintiffs are
successful in these lawsuits, 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, and
recovery of purchased power and purchased gas costs. These
governmental regulations significantly influence the Company's
operating environment and may affect its ability to recover costs
from its customers. The Company is 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.
Risks Relating to the Company's Independent Power Production
Business
There are risks involved with the growth strategies of the Company's
independent power production business. If the Company does not
identify a purchaser for the power to be generated from its proposed
113-megawatt coal-fired electric generation station in Montana it
may not complete construction or commence operation of that
facility, which may result in an asset impairment.
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 March 31, 2003, the Company's investment in
this project was approximately $27.5 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.
Risks Relating to Foreign Operations
The value of the Company's investment in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency exchange rates in countries where the Company
does business.
The Company is subject to political, regulatory and economic
conditions and changes in currency exchange rates in foreign
countries where the Company does business. Significant changes in
the political, regulatory or economic environment in these countries
could negatively affect the value of the Company's investments
located in these countries. Also, since the Company is unable to
predict the fluctuations in the foreign currency exchange rates,
these fluctuations may have an adverse impact on the Company's
results of operations.
The Company's 49 percent equity method investment in a 220-
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.
Other Risks
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 greater resources
and more 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.
Weather conditions can adversely affect the Company's operations and
revenues.
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.
In addition, severe weather can be destructive, causing outages
and/or property damage, which could require additional costs to be
incurred. As a result, adverse weather conditions could negatively
affect the Company's results of operations and financial condition.
The Company's financial results may be impacted by important factors
described below:
Following are some specific factors that should be considered for
a better understanding of the Company's financial condition. These
factors are important factors that may impact the Company's
financial results in future periods.
- 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 common share, diluted, before the cumulative
effect of the change in accounting for asset retirement obligations
as required by the adoption of SFAS No. 143, are projected in the
range of $2.00 to $2.25. Including the $7.6 million after-tax
cumulative effect of the accounting change, 2003
earnings per common share, diluted, are projected to be in the
range of $1.90 to $2.15.
- - The Company expects the percentage of 2003 earnings per common
share, diluted, after the cumulative effect of an accounting change
by quarter to be in the following approximate ranges:
- Second Quarter - 19 percent to 24 percent
- Third Quarter - 36 percent to 41 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 under
construction near Glendive, Montana at an estimated cost of $20
million, to be operational by June 1, 2003. Montana-Dakota expects
to build an additional 80-megawatts of peaking capacity by 2007.
These projects are expected to be recovered in rates and will be
used to meet Montana-Dakota's need for additional generating
capacity.
- - Regulatory approval has been received from the North Dakota
Public Service Commission and the South Dakota Public Utilities
Commission on Montana-Dakota's plans to purchase energy from a 20-
megawatt, wind energy farm in North Dakota. This wind energy farm
is expected to be on line by late 2003.
- - Montana-Dakota is working with the state of North Dakota to
determine the feasibility of constructing a 250-megawatt to 500-
megawatt lignite-fired power plant in western North Dakota. The
next preliminary decision on this matter is expected in late 2003.
- - On April 25, 2003, Montana-Dakota was notified that a new labor
contract, effective May 1, 2003 through April 30, 2007, was ratified
with the International Brotherhood of Electrical Workers. The
existing contract, as described in Items 1 and 2 - Business and
Properties - General in the Company's 2002 Form 10-K, was scheduled
to expire on April 30, 2003.
- - On March 28, 2003, a new coal supply contract with Westmoreland
Coal Company was signed. The agreement allows for fuel supply to
the Lewis & Clark Electric Generating Station effective through
December 31, 2007. The prior contract, as described in Items 1 and
2 - Business and Properties - General in the Company's 2002 Form 10-
K, was scheduled to expire on March 31, 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 52 million decatherms.
- - Montana-Dakota filed an application with the SDPUC seeking an
increase in natural gas retail rates of 5.8 percent above current
rates. Great Plains filed an application with the MPUC seeking an
increase in natural gas retail rates of 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 17 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. During 2002, a number of
factors affected margins, including the write-off of certain
receivables and restructuring of the engineering function which
amounts totaled approximately $5.2 million after tax. This segment
anticipates margins in 2003 to increase over 2002 levels.
- - This segment's work backlog as of March 31, 2003, was
approximately $158 million.
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 levels.
- - 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, construction could be
completed 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 of approximately 20 percent over 2002 record
levels.
- - This segment expects to drill more than 400 wells in 2003.
- - This segment had approximately 100 wells related to its coalbed
natural gas development in the Powder River Basin in Montana and
Wyoming that were not producing natural gas at March 31, 2003, but
are expected to begin producing natural gas in the future.
- - Natural gas prices in the Rocky Mountain region for May 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 May 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 April 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.
CIG is an index pricing point related to Colorado Interstate Gas
Co.'s system and Ventura is an index pricing point related to
Northern Natural Gas Co.'s system.
- - This segment 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 representing approximately 30
percent to 35 percent of 2003 estimated annual oil production.
- - The Company has begun hedging a portion of its 2004 estimated
annual natural gas production and will continue to evaluate
additional opportunities in the near future.
- - 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.
In one such case, the United States District Court in Billings,
Montana (Federal District Court) held that water produced in
association with coalbed natural gas and discharged into rivers
and streams was not a pollutant under the Federal Clean Water Act
and that state statutes exempt such unaltered groundwater from
Montana Pollution Discharge Elimination System permit
requirements. On April 10, 2003, the United States Circuit Court
of Appeals for the Ninth Circuit (Circuit Court) reversed the
Federal District Court's decision. On April 29, 2003, Fidelity
filed a motion to stay the effect of the Circuit Court's decision
pending the United States Supreme Court's (Supreme Court) final
disposition of issues that will be presented to the Supreme Court
in a petition for writ of certiorari. On May 5, 2003, the Circuit
Court granted Fidelity's motion to stay the effect of its decision
pending the Supreme Court's review of the matter. The petition
for writ of certiorari must be filed by Fidelity with the Supreme
Court on or before July 9, 2003. Fidelity believes the ultimate
outcome of the proceeding will not have a material effect on its
existing coalbed natural gas operations or future development of
its coalbed natural gas properties. In the event a penalty is
ultimately imposed in that proceeding, Fidelity believes it will
be minimal because any unpermitted discharges were of small
amounts, were for a short duration, were quickly remediated and
are now fully permitted.
Fidelity believes the ultimate outcome of other lawsuits filed in
connection with its coalbed natural gas development would not have
a material effect on its existing coalbed natural gas operations,
but could have a material effect on Fidelity's future development
of its coalbed natural gas properties.
For further information on these proceedings, see Risk Factors and
Cautionary Statements that May Affect Future Results in this Form
10-Q.
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.
- - As of mid-April 2003, this segment had over $325 million in
work backlog.
- - On April 11, 2003, this segment completed acquisitions of a
ready-mixed concrete company and a sand, gravel and aggregate
product company, both in North Dakota, and an aggregate mining and
ready mix supply company in Montana. The companies have combined
annual revenues of approximately $21 million.
- - Three of the five labor contracts that Knife River was
negotiating, as reported in Items 1 and 2 - Business and Properties -
General in the Company's 2002 Form 10-K, have been ratified and
the two remaining contracts are being negotiated. The Company
considers its relations with its employees to be satisfactory.
Independent power production
- - Earnings projections for 2003 for the independent power
production segment include the estimated results from the wind-
powered electric generation facility in California, the natural gas-
fired generating facilities in Colorado, and the Company's 49-
percent ownership in a 220-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.
- - 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 FASB approved SFAS No. 143, "Accounting for
Asset Retirement Obligations." Upon adoption of SFAS No. 143, the
Company recorded a discounted liability of $22.5 million and a
regulatory asset of $493,000, increased net property, plant and
equipment by $9.6 million and recognized a one-time cumulative
effect charge of $7.6 million (net of deferred tax benefit of $4.8
million).
In April 2002, the FASB approved SFAS No. 145, "Rescission of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections." The adoption of SFAS No. 145 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" (FIN 45).
The Company will apply the initial recognition and initial
measurement provisions of FIN 45 to guarantees issued or modified
after December 31, 2002.
In January 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities" (FIN 46). The Company
will prospectively apply the provisions of FIN 46 effective January
31, 2003. The Company is currently evaluating the provisions of FIN
46 which are effective for the first fiscal year or interim period
beginning after June 15, 2003.
For further information on SFAS No. 143, SFAS No. 145, FIN 45
and FIN 46, see Note 8 of Notes to Consolidated Financial
Statements.
Critical Accounting Policies
The Company's critical accounting policies include impairment
of long-lived assets and intangibles, impairment testing of natural
gas and oil properties, revenue recognition, derivatives, purchase
accounting, accounting for the effects of regulation and use of
estimates. There are no material changes in the Company's critical
accounting policies from those reported in the Company's Annual
Report on Form 10-K for the year ended December 31, 2002. For more
information on critical accounting policies, see Part II, Item 7 in
the Company's Annual Report on Form 10-K for the year ended December
31, 2002.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows provided by operating activities in the first
quarter of 2003 increased $6.3 million from the comparable 2002
period, the result of higher depreciation, depletion and
amortization expense of $8.0 million, resulting largely from
increased property, plant and equipment balances and higher
production volumes, and the cumulative effect of an accounting
change of $7.6 million. Partially offsetting the increase in cash
flows from operating activities was a decrease in cash from working
capital items of $8.1 million.
Investing activities --
Cash flows used in investing activities in the first quarter of
2003 increased $93.5 million compared to the comparable 2002 period,
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 $97.3 million, slightly
offset by an increase in proceeds from notes receivable of $3.8
million. Net capital expenditures exclude the noncash transactions
related to acquisitions, including the issuance of the Company's
equity securities. The noncash transactions were $1.1 million and
$15.6 million for the first quarter of 2003 and 2002, respectively.
Financing activities --
Cash flows provided by financing activities in the first
quarter of 2003 increased $87.2 million compared to the comparable
2002 period, largely due to an increase in the issuance of long-term
debt of $86.8 million.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit
pension plans (Pension Plans). There are no material changes in the
Company's Pension Plans from those reported in the Company's Annual
Report on Form 10-K for the year ended December 31, 2002. For
further information on the Company's Pension Plans, see Part II,
Item 7 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002.
Capital expenditures
Net capital expenditures, including the issuance of the
Company's equity securities, for the first three months of 2003 were
$162.1 million and are estimated to be approximately $490 million
for the year 2003. Estimated capital expenditures include those
for:
- Completed acquisitions
- 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 certain construction
costs for a 113-megawatt coal-fired electric generation station, as
previously discussed
- Other growth opportunities
Approximately 25 percent of estimated 2003 net capital
expenditures are for completed acquisitions. 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, actual acquisitions and
capital expenditures may vary significantly from the estimated 2003
capital expenditures referred to above. It is anticipated that the
funds required for capital expenditures will be met from various
sources. These sources include internally generated funds,
commercial paper credit facilities at Centennial and MDU Resources,
as described below, and through the issuance of long-term debt and
the Company's equity securities.
The estimated 2003 capital expenditures referred to above
include completed 2003 acquisitions involving a wind-powered
electric generation facility in California and construction
materials and mining businesses in Montana and North Dakota. Pro
forma financial amounts reflecting the effects of the above
acquisitions are not presented as such acquisitions were not
material to the Company's financial position or results of
operations.
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
March 31, 2003.
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 March 31, 2003. The bank
lines of credit provide for commitment fees at varying rates. There
were no amounts outstanding under the bank lines of credit or the
credit agreement at March 31, 2003. 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, $40.0
million was outstanding at March 31, 2003. The commercial paper
borrowings are classified as long-term debt as the Company intends
to refinance these borrowings on a long-term basis through continued
commercial paper borrowings and as further 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 ratings, 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 bank lines of credit, it would be expected to incur
increased annualized interest expense on its variable rate debt of
approximately $60,000 (after tax) based on March 31, 2003, variable
rate borrowings. Based on the Company's overall interest rate
exposure at March 31, 2003, 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
March 31, 2003. 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 March 31, 2003, the Company could have issued approximately
$333 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.6 times and 4.8 times for the twelve months ended
March 31, 2003 and December 31, 2002, respectively. Additionally,
the Company's first mortgage bond interest coverage was 7.9 times
and 7.7 times for the twelve months ended March 31, 2003 and
December 31, 2002, respectively. Common stockholders' equity as a
percent of total capitalization was 58 percent and 60 percent at
March 31, 2003 and December 31, 2002, respectively.
Centennial Energy Holdings, Inc.
Centennial has a revolving credit agreement with various banks
that supports $330 million of Centennial's $350 million commercial
paper program. There were no outstanding borrowings under the
Centennial credit agreement at March 31, 2003. Under the Centennial
commercial paper program, $150.6 million was outstanding at March
31, 2003. The Centennial commercial paper borrowings are classified
as long-term debt as Centennial intends to refinance these
borrowings on a long-term basis through continued Centennial
commercial paper borrowings 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, $399.6 million was outstanding at
March 31, 2003. 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 ratings, 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 $226,000
(after tax) based on March 31, 2003, variable rate borrowings.
Based on Centennial's overall interest rate exposure at March 31,
2003, 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
March 31, 2003. 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.
Centennial Energy Resources International Inc
Centennial International has a short-term credit agreement that
allows for borrowings of up to $25 million. Under this agreement,
$12.5 million was outstanding at March 31, 2003. Centennial
International is currently evaluating the renewal/extension of 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 March 31, 2003. 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 March 31, 2003.
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 March 31, 2003.
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
There are no material changes in the Company's contractual
obligations on long-term debt, operating leases and purchase
commitments from those reported in the Company's Annual Report on
Form 10-K for the year ended December 31, 2002. For more
information on contractual obligations and commercial commitments,
see Part II, Item 7 in the Company's Annual Report on Form 10-K for
the year ended December 31, 2002.
Centennial has financial guarantees outstanding at March 31,
2003. These guarantees pertain to Centennial's guarantee of certain
obligations in connection with the natural gas-fired electric
generation station in Brazil and as of March 31, 2003, are
approximately $64.7 million. As of March 31, 2003, with respect to
these guarantees, there was approximately $12.7 million outstanding
through 2003, $8.7 million outstanding through 2004 and $43.3
million outstanding through 2006. These guarantees are not
reflected in the consolidated financial statements. For more
information on these guarantees, see Note 18 of Notes to
Consolidated Financial Statements.
As of March 31, 2003, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately $232
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. The
surety bonds were not reflected on the Consolidated Balance Sheets.
Pre-approval of services provided by independent auditors
During the first quarter of 2003, the Company's Audit Committee
pre-approved certain services related to the 2003 annual audit and
certain risk management advisory services in connection with
international operations.
ITEM 3. 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.
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.
For more information on commodity price risk, see Part II, Item 7A
in the Company's Annual Report on Form 10-K for the year ended
December 31, 2002, and Note 12 of Notes to Consolidated Financial
Statements in this Form 10-Q.
The following table summarizes hedge agreements entered into by
a wholly owned subsidiary of the Company, as of March 31, 2003.
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 $ 4.14 2,156 $(494)
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 16,851 $(13,720)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2003 $24.50/$27.62 481 $(474)
Interest rate risk --
There are no material changes to interest rate risk faced by
the Company from those reported in the Company's Annual Report on
Form 10-K for the year ended December 31, 2002. For more
information on interest rate risk, see Part II, Item 7A in the
Company's Annual Report on Form 10-K for the year ended December 31,
2002.
Foreign currency risk --
MDU Brasil has a 49 percent equity investment in a 220-megawatt
natural gas-fired electric generation project (Project) in Brazil,
which has a portion of its borrowings and payables denominated in
U.S. dollars. MDU Brasil 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 10 of Notes to Consolidated Financial
Statements.
MDU Brasil'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 Centennial International as discussed
below. At March 31, 2003, these U.S. dollar denominated obligations
approximated $52.5 million. If, for example, the value of the
Brazilian real decreased in relation to the U.S. dollar by 10
percent, MDU Brasil, with respect to its interest in the Project,
would record a foreign currency transaction loss in net income of
approximately $2.3 million based on the above U.S. dollar
denominated obligations at March 31, 2003. The Project also had
US$37.3 million of Brazilian real denominated obligations at
March 31, 2003.
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
(loss) at March 31, 2003. Foreign currency translation adjustments
on the Project's U.S. dollar denominated borrowings payable to the
subsidiary of $20.0 million at March 31, 2003, are recorded in
accumulated other comprehensive income (loss).
Centennial International's investment in this Project at March
31, 2003, was $20.5 million. Centennial has guaranteed Project
obligations and loans of approximately $64.7 million as of March 31,
2003.
MDU Brasil 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. The Company has also
historically used derivative instruments to manage a portion of the
Company's foreign currency risk and may utilize such instruments in
the future.
ITEM 4. 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 Quarterly Report
on Form 10-Q (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 II -- OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
On April 10, 2003, the State District Court for Stevens
County, Kansas denied the motion for certification of the Quinque
legal proceeding as a class action. On April 22, 2003, the State
District Court stayed proceedings on all motions pending the
filing of a motion for leave to amend by the plaintiffs. On May
12, 2003, the plaintiffs filed a motion to file an amended class
action petition. Neither Williston Basin nor Montana-Dakota were
named as defendants in the proposed amended class action
petition, which is currently pending.
For more information on the above legal action see Note 18 of
Notes to Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between January 1, 2003 and March 31, 2003, the Company issued
53,891 shares of Common Stock, $1.00 par value, and the Preference
Share Purchase Rights appurtenant thereto, as part of the
consideration paid by the Company in the acquisition of a business
acquired by the Company in a prior period. The Common Stock and
Rights issued by the Company in this transaction were issued in a
private transaction exempt from registration under the Securities
Act of 1933 pursuant to Section 4(2) thereof, Rule 506 promulgated
thereunder, or both. The classes of persons to whom these
securities were sold were either accredited investors or other
persons to whom such securities were permitted to be offered under
the applicable exemption.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual Meeting of Stockholders was held on
April 22, 2003. One proposal was submitted to stockholders as
described in the Company's Proxy Statement dated March 7, 2003, and
was voted upon and approved by stockholders at the meeting. The
table below briefly describes the proposal and the results of the
stockholder votes.
Shares
Shares Against or Broker
For Withheld Abstentions Non-Votes
Proposal to elect three directors:
For terms expiring in 2006 --
Harry J. Pearce 65,272,526 462,795 --- ---
Homer A. Scott, Jr. 65,219,081 516,240 --- ---
Sister Thomas Welder, O.S.B. 65,200,782 534,539 --- ---
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
12 Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
99 Statement Furnished Pursuant to Section 906 of
Sarbanes - Oxley Act of 2002
b) Reports on Form 8-K
Form 8-K was filed on March 13, 2003. Under Item 5 -- Other
Events and Item 7 -- Financial Statements and Exhibits, the
Company reported the press release issued March 11, 2003,
regarding revised earnings guidance for 2003.
Form 8-K was filed on January 29, 2003. Under Item 5 -- Other
Events and Item 7 -- Financial Statements and Exhibits, the
Company reported the press release issued January 27, 2003,
regarding earnings for 2002.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE: May 14, 2003 BY /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President,
Treasurer and Chief
Financial Officer
BY /s/ Vernon A. Raile
Vernon A. Raile
Senior Vice President,
Controller and Chief
Accounting Officer
FORM 10-Q CERTIFICATION
I, Martin A. White, certify that:
1. I have reviewed this quarterly report on Form 10-Q of MDU
Resources Group, Inc.;
2. Based on my knowledge, this quarterly 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
quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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
quarterly 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 we 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 quarterly 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 quarterly report (the
"Evaluation Date"); and
c. presented in this quarterly 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
function):
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 quarterly report whether or not 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: May 14, 2003 /s/ Martin A. White
Martin A. White
Chairman of the Board, President
and Chief Executive Officer
FORM 10-Q CERTIFICATION
I, Warren L. Robinson, certify that:
1. I have reviewed this quarterly report on Form 10-Q of MDU
Resources Group, Inc.;
2. Based on my knowledge, this quarterly 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
quarterly report;
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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
quarterly 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 we 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 quarterly 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 quarterly report (the
"Evaluation Date"); and
c. presented in this quarterly 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
function):
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 quarterly report whether or not 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: May 14, 2003 /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President,
Treasurer and Chief Financial
Officer
EXHIBIT INDEX
Exhibit No.
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
99 Statement Furnished Pursuant to Section 906 of
Sarbanes - Oxley Act of 2002