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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 SEPTEMBER 30, 2002
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 the number of shares outstanding of each of the
issuer's classes of common stock, as of November 6, 2002:
71,672,380 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 -- Safe Harbor for Forward-looking Statements.
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.
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) and Centennial Holdings Capital Corp.
(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 and provides energy-
related management services, as well as cable and pipeline
locating services. 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 and asphalt, as well
as value-added products and services in the north central
and western United States, including Alaska and Hawaii.
Utility Services is a diversified infrastructure company
specializing in engineering, design and build capability for
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 Capital invests in new growth and synergistic
opportunities, including independent power production, which
are not directly being pursued by the existing business
units but which are consistent with the Company's philosophy
and growth strategy. These activities are reflected in the
pipeline and energy services segment.
The Company, through its wholly owned subsidiary, MDU Resources
International, Inc. (MDU 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 pipeline and energy services
segment.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Nine Months Ended September 30, 2002 and 2001
Consolidated Balance Sheets --
September 30, 2002 and 2001, and December 31, 2001
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 2002 and 2001
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 Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
(In thousands, except per share amounts)
Operating revenues $612,398 $551,680 $1,474,550 $1,739,345
Operating expenses:
Fuel and purchased power 14,500 14,982 41,568 42,703
Purchased natural gas sold 4,644 36,840 60,120 502,394
Operation and maintenance 445,672 356,677 1,023,562 823,052
Depreciation, depletion and
amortization 40,589 36,205 114,536 102,737
Taxes, other than income 16,822 13,737 47,601 41,352
522,227 458,441 1,287,387 1,512,238
Operating income 90,171 93,239 187,163 227,107
Other income -- net 6,910 1,855 11,729 16,416
Interest expense 11,731 11,459 33,253 34,171
Income before income taxes 85,350 83,635 165,639 209,352
Income taxes 31,419 32,889 63,133 82,502
Net income 53,931 50,746 102,506 126,850
Dividends on preferred stocks 189 190 567 571
Earnings on common stock $ 53,742 $ 50,556 $ 101,939 $ 126,279
Earnings per common share -- basic $ .76 $ .75 $ 1.45 $ 1.89
Earnings per common share -- diluted $ .75 $ .74 $ 1.44 $ 1.87
Dividends per common share $ .24 $ .23 $ .70 $ .67
Weighted average common shares
outstanding -- basic 70,923 67,650 70,288 66,781
Weighted average common shares
outstanding -- diluted 71,344 68,127 70,756 67,519
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, September 30, December 31,
2002 2001 2001
(In thousands, except shares
and per share amount)
ASSETS
Current assets:
Cash and cash equivalents $ 42,806 $ 57,817 $ 41,811
Receivables, net 363,568 357,027 285,081
Inventories 102,130 95,669 95,341
Deferred income taxes 15,020 14,839 18,973
Prepayments and other current assets 39,482 27,722 40,286
563,006 553,074 481,492
Investments 43,339 37,917 38,198
Property, plant and equipment 2,979,495 2,699,796 2,738,612
Less accumulated depreciation,
depletion and amortization 1,046,987 918,468 946,470
1,932,508 1,781,328 1,792,142
Deferred charges and other assets:
Goodwill 185,205 158,619 173,997
Other intangible assets, net 84,682 76,410 76,234
Other 60,889 65,123 61,008
330,776 300,152 311,239
$2,869,629 $2,672,471 $2,623,071
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 10,000 $ --- $ ---
Long-term debt and preferred
stock due within one year 22,606 11,131 11,185
Accounts payable 148,312 141,950 110,649
Taxes payable 17,960 28,984 11,826
Dividends payable 17,335 15,840 16,108
Other accrued liabilities 104,720 91,191 95,559
320,933 289,096 245,327
Long-term debt 832,533 843,915 783,709
Deferred credits and other liabilities:
Deferred income taxes 360,872 327,560 342,412
Other liabilities 139,021 118,013 125,552
499,893 445,573 467,964
Preferred stock subject to mandatory
redemption 1,300 1,400 1,300
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Shares issued --
$1.00 par value, 71,681,396
at September 30, 2002, 69,386,316
at September 30, 2001 and
70,016,851 at December 31, 2001) 71,681 69,386 70,017
Other paid-in capital 690,139 626,655 646,521
Retained earnings 446,820 381,752 394,641
Accumulated other comprehensive
income (loss) (5,044) 3,320 2,218
Treasury stock at cost - 239,521
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 1,199,970 1,077,487 1,109,771
Total stockholders' equity 1,214,970 1,092,487 1,124,771
$2,869,629 $2,672,471 $2,623,071
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
2002 2001
(In thousands)
Operating activities:
Net income $102,506 $126,850
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 114,536 102,737
Deferred income taxes and investment tax credit 12,686 8,448
Changes in current assets and liabilities,
net of acquisitions:
Receivables (64,437) 54,776
Inventories (4,585) (26,844)
Other current assets (2,743) 7,460
Accounts payable 27,941 (55,426)
Other current liabilities 14,142 43,667
Other noncurrent changes 1,594 (2,867)
Net cash provided by operating activities 201,640 258,801
Investing activities:
Capital expenditures (212,584) (227,829)
Acquisitions, net of cash acquired (14,802) (112,743)
Net proceeds from sale or disposition of property 5,699 34,847
Investments (2,827) 3,041
Proceeds from notes receivable 4,000 4,000
Net cash used in investing activities (220,514) (298,684)
Financing activities:
Net change in short-term borrowings 10,000 (8,000)
Issuance of long-term debt 68,039 158,807
Repayment of long-term debt (8,043) (96,031)
Proceeds from issuance of common stock, net 200 52,157
Dividends paid (50,327) (45,745)
Net cash provided by financing activities 19,869 61,188
Increase in cash and cash equivalents 995 21,305
Cash and cash equivalents -- beginning of year 41,811 36,512
Cash and cash equivalents -- end of period $ 42,806 $ 57,817
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
September 30, 2002 and 2001
(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, 2001 (2001 Annual Report), and the standards of
accounting measurement set forth in Accounting Principles Board
Opinion No. 28 and any amendments thereto adopted by the
Financial Accounting Standards Board. 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 2001 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. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of
September 30, 2002 and 2001, and December 31, 2001 was $8.0
million, $5.7 million and $5.8 million, respectively.
3. 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.
4. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Nine Months Ended
September 30,
2002 2001
(In thousands)
Interest, net of amount capitalized $ 27,434 $28,158
Income taxes $ 42,421 $57,528
5. 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.
6. New accounting standards
In June 2001, the Financial Accounting Standards Board
(FASB) approved Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (SFAS No.
143). 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. The Company will
adopt SFAS No. 143 on January 1, 2003, but has not yet
quantified the effects of adopting SFAS No. 143 on its
financial position or results of operations.
In April 2002, the FASB approved Statement of Financial
Accounting Standards No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" (SFAS No. 145). 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 Accounting Principles Board 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 Company
believes the adoption of SFAS No. 145 will not have a material
effect on its financial position or results of operations.
In June 2002, the Emerging Issues Task Force
(EITF) adopted the position in EITF Issue No. 02-3,
"Recognition and Reporting of Gains and Losses on Energy
Trading Contracts under EITF Issues No. 98-10,
'Accounting for Contracts Involved in Energy Trading and
Risk Management Activities' (EITF No. 98-10), and No. 00-
17, 'Measuring the Fair Value of Energy-related
Contracts in Applying Issue No. 98-10'" (EITF No. 02-3)
that mark-to-market gains and losses on energy trading
contracts should be reported on a net basis in the
income statement whether or not settled physically in
financial statements issued for periods ending after
July 15, 2002. However, at the October 25, 2002 EITF
meeting, the EITF reached a consensus to rescind EITF
No. 98-10, the impact of which is to preclude mark-to-
market accounting for all energy trading contracts not
within the scope of Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133). In
addition, the EITF reached a consensus that gains and
losses on derivative instruments within the scope of
SFAS No. 133 should be shown net in the income statement
if the derivative instruments are held for trading
purposes. The consensuses reached effectively supersede
the consensuses reached on this issue at the June, 2002
EITF meeting. The rescission of EITF No. 98-10 is
effective for fiscal periods beginning after December 15,
2002. Energy trading contracts not within the scope
of SFAS No. 133 purchased after October 25, 2002, but
prior to the implementation of the consensus are not
permitted to apply mark-to-market accounting. The
Company has not yet determined the financial statement
effect, if any, of the adoption of the October 25, 2002,
EITF positions.
In June 2002, the FASB approved Statement of Financial
Accounting Standards No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs
associated with exit or disposal activities and nullifies EITF
Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)" (EITF
No. 94-3). SFAS No. 146 requires recognition of a liability
for a cost associated with an exit or disposal activity when
the liability is incurred, as opposed to when the entity
commits to an exit plan under EITF No. 94-3. SFAS No. 146 is
to be applied prospectively to exit or disposal activities
initiated after December 31, 2002. The Company believes the
adoption of SFAS No. 146 will not have a material effect on its
financial position or results of operations.
7. Derivative instruments
The Company's policy allows the use of derivative
instruments as part of an overall energy price, foreign
currency and interest rate risk management program to
efficiently manage and minimize commodity price, foreign
currency and interest rate risk. The Company's policy
prohibits the use of derivative instruments for speculating to
take advantage of market trends and conditions and the Company
has procedures in place to monitor compliance with its
policies. The Company is exposed to credit-related losses in
relation to derivative instruments in the event of
nonperformance by counterparties. The Company's policy
requires settlement of natural gas and oil price derivative
instruments monthly, settlement of foreign currency derivative
transactions yearly and settlement of interest rate derivative
instruments within 90 days. The Company has policies and
procedures, which management believes minimize credit-risk
exposure. These policies and procedures include an evaluation
of potential counterparties' credit ratings and credit exposure
limitations. Accordingly, the Company does not anticipate any
material effect to its financial position or results of
operations as a result of nonperformance by counterparties.
In the event a derivative instrument does not qualify for
hedge accounting because it is no longer highly effective in
offsetting changes in cash flows of a hedged item; or if the
derivative instrument expires or is sold, terminated, or
exercised; or if management determines that designation of the
derivative instrument as a hedge instrument is no longer
appropriate, hedge accounting will be discontinued, and the
derivative instrument would continue to be carried at fair
value with changes in its fair value recognized in earnings.
In these circumstances, the net gain or loss at the time of
discontinuance of hedge accounting would remain in other
comprehensive income (loss) until the period or periods during
which the hedged forecasted transaction affects earnings, at
which time the net gain or loss would be reclassified into
earnings. In the event a cash flow hedge is discontinued
because it is unlikely that a forecasted transaction will
occur, the derivative instrument would continue to be carried
on the balance sheet at its fair value, and gains and losses
that were accumulated in other comprehensive income (loss)
would be recognized immediately in earnings. In the event of a
sale, termination or extinguishment of a foreign currency
derivative, the resulting gain or loss would be recognized
immediately in earnings. The Company's policy requires
approval to terminate a derivative instrument prior to its
original maturity.
Certain subsidiaries of the Company held derivative
instruments designated as cash flow hedging instruments as well
as a foreign currency derivative which was not designated as a
hedge.
Hedging activities
Certain subsidiaries of the Company utilize natural gas
and oil price swap and natural gas collar agreements, to manage
a portion of the market risk associated with fluctuations in
the price of natural gas and oil on the subsidiaries'
forecasted sales of natural gas and oil production. Centennial
entered into an interest rate swap agreement which expired in
the fourth quarter of 2001. The objective for holding the
interest rate swap agreement was to manage a portion of
Centennial's interest rate risk on the forecasted issuance of
fixed-rate debt under Centennial's commercial paper program.
Such subsidiaries designated each of the natural gas and oil
price swap and collar agreements as a hedge of the forecasted
sale of natural gas and oil production and designated the
interest rate swap agreement as a hedge of the risk of changes
in interest rates on Centennial's forecasted issuances of fixed-
rate debt under Centennial's commercial paper program.
On an ongoing basis, such subsidiaries of the Company
adjust their Consolidated Balance Sheets to reflect the current
fair market value of their swap and collar agreements. The
related gains or losses on these agreements are recorded in
common stockholders' equity as a component of other
comprehensive income (loss). At the date the underlying
transaction occurs, the amounts accumulated in other
comprehensive income (loss) are reported in the Consolidated
Statements of Income. To the extent that the hedges are not
effective, the ineffective portion of the changes in fair
market value is recorded directly in earnings.
For the three months and nine months ended September 30,
2002 and 2001, such subsidiaries of the Company recognized the
ineffectiveness of cash flow hedges, which is included in
operating revenues and interest expense for the natural gas and
oil price swap and collar agreements and the interest rate swap
agreement, respectively. For the three months and nine months
ended September 30, 2002 and 2001, the amount of hedge
ineffectiveness recognized was immaterial. For the three
months and nine months ended September 30, 2002 and 2001, such
subsidiaries 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 September 30, 2002,
the maximum term of the subsidiaries' swap and collar
agreements, in which the subsidiaries of the Company are
hedging their exposure to the variability in future cash flows
for forecasted transactions is 15 months. The subsidiaries of
the Company estimate that over the next twelve months net
losses of approximately $450,000 will be reclassified from
accumulated other comprehensive income (loss) into earnings,
subject to changes in natural gas and oil market prices, as the
hedged transactions affect earnings.
Foreign currency derivative
On August 12, 2002, a subsidiary of the Company entered
into a foreign currency collar agreement for a notional amount
of $21.3 million with a fixed price floor of R$3.10 and a fixed
price ceiling of R$3.40 to manage a portion of its foreign
currency risk. This subsidiary has a 49 percent equity
investment in a 200 megawatt natural gas fired electric
generation project in Brazil which has a portion of its
borrowings and payables denominated in U.S. dollars. This
subsidiary has exposure to currency exchange risk as a result
of fluctuations in currency exchange rates between the U.S.
dollar and the Brazilian real. The term of the collar
agreement is from August 12, 2002 through February 3, 2003, and
the collar agreement settles on February 3, 2003.
The foreign currency collar agreement has not been
designated as a hedge and is recorded at fair value on the
Consolidated Balance Sheets. Gains or losses on this
derivative instrument are recorded in other income -- net on
the Consolidated Statements of Income.
8. Comprehensive income
On January 1, 2001, the Company recorded a cumulative-
effect adjustment in accumulated other comprehensive loss to
recognize all derivative instruments designated as hedges at
fair value. As of September 30, 2002 and 2001, the Company has
recorded unrealized gains and losses on natural gas and oil
price swap and collar agreements and an interest rate swap
agreement which qualify for hedge accounting. As of
September 30, 2002, the Company also recorded a minimum pension
liability adjustment. These amounts are reflected in the
following table.
The Company's comprehensive income, and the components of
other comprehensive income (loss), net of taxes, were as
follows:
Three Months Ended
September 30,
2002 2001
(In thousands)
Net income $ 53,931 $ 50,746
Other comprehensive income (loss) --
Net unrealized gain (loss) on derivative
instruments qualifying as hedges:
Net unrealized gain (loss) on derivative
instruments arising during the
period, net of tax of $806 and
$1,191 in 2002 and 2001, respectively (1,234) 1,824
Less: Reclassification adjustment for
gain on derivative instruments
included in net income, net of
tax of $789 and $992 in
2002 and 2001, respectively 1,208 1,519
Net unrealized gain (loss) on derivative
instruments qualifying as hedges (2,442) 305
Comprehensive income $ 51,489 $ 51,051
Nine Months Ended
September 30,
2002 2001
(In thousands)
Net income $102,506 $126,850
Other comprehensive income (loss) --
Net unrealized gain (loss) on derivative
instruments qualifying as hedges:
Unrealized loss on derivative
instruments at January 1, 2001,
due to cumulative effect of a
change in accounting principle,
net of tax of $3,970 --- (6,080)
Net unrealized gain (loss) on derivative
instruments arising during the
period, net of tax of $723 and
$2,782 in 2002 and 2001, respectively (1,107) 4,262
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $1,185 and $3,355 in
2002 and 2001, respectively 1,815 (5,138)
Net unrealized gain (loss) on derivative
instruments qualifying as hedges (2,922) 3,320
Minimum pension liability adjustment,
net of tax of $2,781 (4,340) ---
(7,262) 3,320
Comprehensive income $ 95,244 $130,170
9. Goodwill and other intangible assets
In June 2001, the FASB approved Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142). SFAS No. 142 changes the accounting
for goodwill and intangible assets and requires that goodwill
no longer be amortized but be tested for impairment at least
annually at the reporting unit level in accordance with SFAS
No. 142. Recognized intangible assets with determinable useful
lives should be amortized over their useful life and reviewed
for impairment in accordance with Statement of Financial
Accounting Standards No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS No. 144). The Company
adopted SFAS No. 142 on January 1, 2002. The Company completed
its transitional goodwill impairment testing and determined
that no impairment existed as of January 1, 2002. Therefore,
no impairment loss has been recorded for the three months and
nine months ended September 30, 2002, in connection with the
adoption of SFAS No. 142.
On January 1, 2002, in accordance with SFAS No. 142, the
Company ceased amortization of its goodwill recorded in
business combinations which occurred on or before June 30,
2001. The following information is presented as if SFAS No.
142 was adopted as of January 1, 2001. The reconciliation of
previously reported earnings and earnings per share to the
amounts adjusted for the exclusion of goodwill amortization net
of the related income tax effect is as follows:
Three Months Ended
September 30,
2002 2001
(In thousands, except
per share amounts)
Reported earnings on common stock $ 53,742 $50,556
Add: Goodwill amortization, net of tax --- 1,502
Adjusted earnings on common stock $ 53,742 $52,058
Reported earnings per common
share -- basic $ .76 $ .75
Add: Goodwill amortization, net of tax --- .02
Adjusted earnings per common
share -- basic $ .76 $ .77
Reported earnings per common
share -- diluted $ .75 $ .74
Add: Goodwill amortization, net of tax --- .02
Adjusted earnings per common
share -- diluted $ .75 $ .76
Nine Months Ended
September 30,
2002 2001
(In thousands, except
per share amounts)
Reported earnings on common stock $101,939 $126,279
Add: Goodwill amortization, net of tax --- 3,294
Adjusted earnings on common stock $101,939 $129,573
Reported earnings per common
share -- basic $ 1.45 $ 1.89
Add: Goodwill amortization, net of tax --- .05
Adjusted earnings per common
share -- basic $ 1.45 $ 1.94
Reported earnings per common
share -- diluted $ 1.44 $ 1.87
Add: Goodwill amortization, net of tax --- .05
Adjusted earnings per common
share -- diluted $ 1.44 $ 1.92
The changes in the carrying amount of goodwill for the
nine months ended September 30, 2002, by business segment are
as follows:
Net
Balance Goodwill Balance
as of Acquired as of
January 1, During September 30,
2002 the Year 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 1,083 62,992
Pipeline and energy
services 9,336 158 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 9,967 112,719
Total $ 173,997 $ 11,208 $ 185,205
Included in other intangible assets on the Company's
Consolidated Balance Sheets are the following:
September 30,September 30,December 31,
2002 2001 2001
(In thousands)
Amortizable intangible
assets:
Leasehold rights $ 79,005 $ 72,780 $ 72,955
Accumulated amortization (2,091) (964) (1,149)
76,914 71,816 71,806
Noncompete agreements 12,090 12,030 12,034
Accumulated amortization (9,234) (8,655) (8,811)
2,856 3,375 3,223
Other 5,149 1,371 1,377
Accumulated amortization (237) (152) (172)
4,912 1,219 1,205
Total $ 84,682 $ 76,410 $ 76,234
Amortization expense for intangible assets for the three
months and nine months ended September 30, 2002, was
approximately $727,000 and $1.4 million, respectively.
Estimated amortization expense for intangible assets is $2.7
million in 2002, $3.1 million in 2003, $3.0 million in 2004,
$3.3 million in 2005, $2.6 million in 2006 and $71.4 million
thereafter.
10. 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.
11. Business segment data
The Company's reportable segments are those that are based
on the Company's method of internal reporting, which generally
segregates the strategic business units due to differences in
products, services and regulation.
The Company's operations are conducted through six
business segments. The vast majority of the Company's
operations are located within the United States. The Company
also has investments in foreign countries, which largely
consists of an investment in a natural gas fired electric
generation station in Brazil. 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
engineering, design and build capability for 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 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. Energy-
related management services as well as cable and pipeline
locating services also are provided. The pipeline and energy
services segment includes investments in domestic and
international growth opportunities, including 213 megawatts of
natural gas fired electric generating facilities in Colorado,
and a 49 percent equity interest in a natural gas fired
electric generation station in Brazil. 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 other
related construction materials, including ready-mixed concrete,
cement and asphalt, as well as value-added products and
services in the north central and western United States,
including Alaska and Hawaii.
In 2001, the Company sold its coal operations to
Westmoreland Coal Company for $28.2 million in cash, including
final settlement cost adjustments. The sale of the coal
operations was effective April 30, 2001. Included in the sale
were active coal mines in North Dakota and Montana, coal sales
agreements, reserves and mining equipment, and certain
development rights at the former Gascoyne Mine site in North
Dakota. The Company retains ownership of coal reserves and
leases at its former Gascoyne Mine site. The Company recorded
a gain of $11.0 million ($6.6 million after tax) included in
other income - net on the Company's Consolidated Statements of
Income from the sale in the second quarter of 2001.
Segment information follows the same accounting policies
as described in Note 1 of the Company's 2001 Annual Report.
Segment information included in the accompanying Consolidated
Statements of Income is as follows:
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended September 30, 2002
Electric $ 41,515 $ --- $ 4,463
Natural gas distribution 16,821 --- (2,646)
Utility services 113,419 --- 1,628
Pipeline and energy
services 21,245 7,171 9,944
Natural gas and oil
production 40,785 1,383 6,953
Construction materials
and mining 378,613 --- 33,400
Intersegment eliminations --- (8,554) ---
Total $ 612,398 $ --- $ 53,742
Three Months
Ended September 30, 2001
Electric $ 48,154 $ --- $ 8,265
Natural gas distribution 18,710 --- (2,747)
Utility services 92,208 --- 3,405
Pipeline and energy
services 59,430 5,391 3,895
Natural gas and oil
production 31,579 10,891 10,519
Construction materials
and mining 301,599 --- 27,219
Intersegment eliminations --- (16,282) ---
Total $ 551,680 $ --- $ 50,556
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Nine Months
Ended September 30, 2002
Electric $ 117,877 $ --- $ 9,627
Natural gas distribution 122,652 --- 1,057
Utility services 338,051 --- 3,811
Pipeline and energy
services 77,155 39,188 15,521
Natural gas and oil
production 117,293 31,046 37,363
Construction materials
and mining 701,522 --- 34,560
Intersegment eliminations --- (70,234) ---
Total $1,474,550 $ --- $ 101,939
Nine Months
Ended September 30, 2001
Electric $ 129,143 $ --- $ 15,224
Natural gas distribution 200,809 --- (1,620)
Utility services 236,710 4 9,321
Pipeline and energy
services 454,819 34,197 9,656
Natural gas and oil
production 121,310 48,192 56,440
Construction materials
and mining 591,538 5,016* 37,258
Intersegment eliminations --- (82,393) ---
Total $1,734,329 $ 5,016* $ 126,279
* In accordance with the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Regulation", intercompany coal sales are not eliminated.
On April 1, 2000, Fidelity Exploration & Production
Company (Fidelity), an indirect wholly owned subsidiary of the
Company, purchased substantially all of the assets of Preston
Reynolds & Co., Inc. (Preston), a coalbed natural gas
development operation based in Colorado with related oil and
gas leases and properties in Montana and Wyoming. Pursuant to
the asset purchase and sale agreement, Preston could, but was
not obligated to purchase, acquire and own an undivided 25
percent working interest (Seller's Option Interest) in certain
oil and gas leases or properties acquired and/or generated by
Fidelity. Fidelity had the right, but not the obligation, to
purchase Seller's Option Interest for an amount as specified in
the agreement. On July 10, 2002, Fidelity purchased the
Seller's Option Interest.
12. Equity Method Investment
As reported in the Company's Form 8-K which was filed on
October 23, 2002, the Company reported the press release issued
October 22, 2002, regarding earnings for the quarter ended
September 30, 2002. In this press release, the Company
reported earnings from its subsidiary's 49 percent owned
Brazilian operations in the amount of $4.0 million, largely
attributable to foreign currency gains on Brazilian real-
denominated obligations. The press release reported that while
the matter has not been finally resolved, the Company's
management has initially determined the functional currency for
the 200-megawatt natural gas fired electric generation project to
be the U.S. dollar. The Company's determination is based on the
fact that the contract revenues for the project are largely
indexed to the U.S. dollar. In addition, the majority of
expected operation and maintenance expenses as well as actual
equipment purchases are in U.S. dollars. The press release
also reported that if, however, the Brazilian real is
ultimately deemed to be the functional currency, rather than
recording a $4.0 million gain, the Company would be required
to restate earnings for the three months ended September 30,
2002 to reflect a net loss from Brazilian operations for the
third quarter of approximately $7.5 million, largely from
foreign currency losses related to U.S. dollar-denominated
obligations. This change from a gain to a loss on the equity
method investment would result in earnings and earnings per
common share, diluted, for the three months ended September 30,
2002 of $42.2 million and $.59, respectively and for the
nine months ended September 30, 2002 of $90.4 million and
$1.28, respectively.
At the time of filing this quarterly report on Form 10-Q,
the above matter has not been finally resolved. This matter is
expected to be resolved in the fourth quarter.
13. Acquisitions
During the first nine months of 2002, the Company acquired
construction materials and mining businesses in Minnesota and
Montana, an energy development company in Montana, and utility
services companies in California and Ohio, none of which was
individually material. The total purchase consideration for
these businesses, including the Company's common stock and cash,
was $60.8 million.
On November 1, 2002, the Company's independent power
production subsidiary announced the acquisition of 213
megawatts of natural gas fired electric generating facilities.
Ninety-five percent of the facilities' output is sold to a non-
affiliated utility under long-term power purchase contracts.
The above acquisitions were accounted for under the
purchase method of accounting and accordingly, the acquired
assets and liabilities assumed have been preliminarily recorded
at their respective fair values as of the date of acquisition.
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 businesses are included in the
financial statements since the date of each acquisition. Pro
forma financial amounts reflecting the effects of the above
acquisitions are not presented as such acquisitions were not
material to the Company's financial position or results of
operations.
14. Regulatory matters and revenues subject to refund
On October 7, 2002, Great Plains filed with the Minnesota
Public Utilities Commission (MPUC) for a natural gas rate
increase. The Company is requesting a total of $1.6 million
annually or 6.9 percent above current rates. The Company
requested an interim increase of $1.4 million or 6.1 percent to
be effective within 60 days of the filing of the natural gas
rate increase. A final order from the MPUC is due August 22,
2003.
On June 10, 2002, Montana-Dakota filed with the Wyoming
Public Service Commission (WYPSC) for a natural gas rate
increase. The Company is requesting a total of $662,000
annually or 5.6 percent above current rates. A hearing before
the WYPSC is scheduled for December 10, 2002 and a final order
from the WYPSC is due April 10, 2003.
On May 20, 2002, Montana-Dakota filed with the Montana
Public Service Commission (MTPSC) for a natural gas rate
increase. The Company is requesting a total of $3.6 million
annually or 6.5 percent above current rates. On September 5,
2002, the MTPSC approved an interim increase of $2.1 million
effective with service rendered on and after September 5, 2002.
Montana-Dakota began collecting such rates effective September
5, 2002, which are subject to refund until the MTPSC issues a
final order. On November 7, 2002, the MTPSC approved an
additional interim increase of $300,000 annually effective
November 15, 2002. The additional interim increase is the
result of a Stipulation reached between the Company 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) will be the final
increase in the proceeding. Reserves have not been provided
for the revenues that have been collected subject to refund. A
hearing before the MTPSC is scheduled for December 6, 2002 and
the final order from the MTPSC is due February 20, 2003.
On April 12, 2002, Montana-Dakota filed with the North
Dakota Public Service Commission (NDPSC) for a natural gas rate
increase. The Company is requesting a total of $2.8 million
annually or 4.1 percent above current rates. A hearing before
the NDPSC was held on October 7-8, 2002 and the final order
from the NDPSC is due December 12, 2002.
The NDPSC authorized its Staff to initiate an
investigation into the earnings levels of Montana-Dakota's
North Dakota electric operations based on Montana-Dakota's 2000
Annual Report to the NDPSC. The investigation was based on a
complaint filed with the NDPSC on September 7, 2001, by the
NDPSC Staff. On April 24, 2002, the NDPSC issued an Order
requiring Montana-Dakota to reduce its North Dakota electric
rates by $4.3 million annually, effective May 8, 2002. On
April 25, 2002, Montana-Dakota filed an appeal of the NDPSC
Order in the North Dakota South Central Judicial District Court
(District Court). The filing also requested a stay of the
effectiveness of the NDPSC Order while the appeal is pending.
Montana-Dakota is challenging the NDPSC's determination of the
level of electricity sales to other utilities and the resulting
revenues expected to be received by Montana-Dakota. On May 2,
2002, the District Court granted Montana-Dakota's request for a
stay of a portion of the $4.3 million annual rate reduction
ordered by the NDPSC. Accordingly, Montana-Dakota implemented
an annual rate reduction of $800,000 effective with service
rendered on and after May 8, 2002, rather than the $4.3 million
annual reduction ordered by the NDPSC. The remaining $3.5
million is subject to refund if Montana-Dakota does not prevail
in this proceeding. Oral arguments before the District Court
were held on October 9, 2002, and a ruling is expected in the
near future.
Reserves have been provided for the revenues that have
been collected subject to refund with respect to Montana-
Dakota's pending electric rate reduction.
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 issued an initial decision on
Williston Basin's natural gas rate change application, which
matter is currently pending before and subject to revision by
the FERC.
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.
15. 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 nonrecurring gain in its financial results
for the first quarter of 2002 of approximately $16.6 million
after-tax. As part of the settlement, FOC gave the former
operator a full and complete release, and FOC is not asserting
any such claim against the former operator for periods after
1997.
In March 1997, 11 natural gas producers filed suit in
North Dakota Southwest Judicial District Court (North Dakota
District Court) against Williston Basin and the Company. The
natural gas producers had processing agreements with Koch
Hydrocarbon Company (Koch). Williston Basin and the Company
had natural gas purchase contracts with Koch. The natural gas
producers alleged they were entitled to damages for the breach
of Williston Basin's and the Company's contracts with Koch
although no specific damages were stated. A similar suit was
filed by Apache Corporation (Apache) and Snyder Oil Corporation
(Snyder) in North Dakota Northwest Judicial District Court in
December 1993. The North Dakota Supreme Court in December 1999
affirmed the North Dakota Northwest Judicial District Court
decision dismissing Apache's and Snyder's claims against
Williston Basin and the Company. Based in part upon the
decision of the North Dakota Supreme Court affirming the
dismissal of the claims brought by Apache and Snyder, Williston
Basin and the Company filed motions for summary judgment to
dismiss the claims of the 11 natural gas producers. The
motions for summary judgment were granted by the North Dakota
District Court in July 2000. In March 2001, the North Dakota
District Court entered a final judgment on the July 2000 order
granting the motions for summary judgment. In May 2001, the 11
natural gas producers appealed the North Dakota District
Court's decision by filing a Notice of Appeal with the North
Dakota Supreme Court. On April 16, 2002, the North Dakota
Supreme Court affirmed the summary judgment entered by the
North Dakota District Court. On April 30, 2002, the 11 natural
gas producers filed a petition for rehearing by the North
Dakota Supreme Court. On May 17, 2002, the North Dakota
Supreme Court denied the 11 natural gas producers petition for
rehearing. The 11 natural gas producers filed a petition for a
writ of certiorari with the Supreme Court of the United States,
which was docketed on August 21, 2002. On October 21, 2002,
the Supreme Court of the United States denied the petition for
the writ of certiorari.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia (U.S.
District Court) against Williston Basin and over 70 other
natural gas pipeline companies. Grynberg, acting on behalf of
the United States under the Federal False Claims Act, alleged
improper measurement of the heating content and volume of
natural gas purchased by the defendants resulting in the
underpayment of royalties to the United States. In March 1997,
the U.S. District Court dismissed the suit without prejudice
and the dismissal was affirmed by the United States Court of
Appeals for the D.C. Circuit in October 1998. In June 1997,
Grynberg filed a similar Federal False Claims Act suit against
Williston Basin and Montana-Dakota and filed over 70 other
separate similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. In April 1999, the United States Department of Justice
decided not to intervene in these cases. In response to a
motion filed by Grynberg, the Judicial Panel on Multidistrict
Litigation consolidated all of these cases in the Federal
District Court of Wyoming (Federal District Court). Oral
argument on motions to dismiss was held before the Federal
District Court in March 2000. In May 2001, the Federal
District Court denied Williston Basin's and Montana-Dakota's
motion to dismiss. The matter is currently pending.
The Quinque Operating Company (Quinque), on behalf of
itself and subclasses of gas producers, royalty owners and
state taxing authorities, instituted a legal proceeding in
State District Court for Stevens County, Kansas, (State
District Court) against over 200 natural gas transmission
companies and producers, gatherers, and processors of natural
gas, including Williston Basin and Montana-Dakota. The
complaint, which was served on Williston Basin and Montana-
Dakota in September 1999, contains allegations of improper
measurement of the heating content and volume of all natural
gas measured by the defendants other than natural gas produced
from federal lands. In response to a motion filed by the
defendants in this suit, the Judicial Panel on Multidistrict
Litigation transferred the suit to the Federal District Court
for inclusion in the pretrial proceedings of the Grynberg suit.
Upon motion of plaintiffs, the case has been remanded to State
District Court. In September 2001, the defendants in this suit
filed a motion to dismiss with the State District Court. The
motion to dismiss was denied by the State District Court on
August 19, 2002. The matter is currently pending.
Williston Basin and Montana-Dakota believe the claims of
Grynberg and Quinque are without merit and intend to vigorously
contest these suits. Williston Basin and Montana-Dakota
believe it is not probable that Grynberg and Quinque will
ultimately succeed given the current status of the litigation.
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, now owned by MBI, 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. Based upon a review of
the Portland Harbor sediment contamination evaluation by the
Oregon State Department of Environmental Quality and other
information available, MBI does not believe it is a Responsible
Party. In addition, MBI intends to seek indemnity for any and
all liabilities incurred in relation to the above matters from
Georgia-Pacific West, Inc., the seller of the commercial
property site to MBI, 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
Certain subsidiaries of the Company have financial
guarantees outstanding at September 30, 2002. These guarantees
as of September 30, 2002, are approximately $31.2 million, of
which approximately $27.8 million pertain to Centennial's
guarantee of certain obligations in connection with the natural
gas fired electric generation station in Brazil, as discussed
in Notes 10 and 15 of Notes to Consolidated Financial
Statements in the 2001 Annual Report and Items 2 and 3 of Part
I of this Quarterly Report on Form 10-Q. As of September 30,
2002, with respect to these guarantees, there were
approximately $27.8 million outstanding through 2003, $1.4
million outstanding through 2004 and $2.0 million outstanding
thereafter. These guarantees are not reflected in the
consolidated financial statements.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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; Centennial
Capital, which invests in domestic growth opportunities; and MDU
International, which invests in international growth opportunities.
Natural gas and oil production includes the natural gas and oil
acquisition, exploration and production operations of WBI Holdings,
while construction materials and mining includes the results of
Knife River's operations.
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 Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
Electric $ 4.5 $ 8.3 $ 9.6 $15.2
Natural gas distribution (2.6) (2.7) 1.0 (1.6)
Utility services 1.6 3.4 3.8 9.3
Pipeline and energy services 9.9 3.9 15.5 9.7
Natural gas and oil production 6.9 10.5 37.4 56.4
Construction materials and
mining 33.4 27.2 34.6 37.3
Earnings on common stock $ 53.7 $ 50.6 $101.9 $126.3
Earnings per common
share - basic $ .76 $ .75 $ 1.45 $ 1.89
Earnings per common
share - diluted $ .75 $ .74 $ 1.44 $ 1.87
Return on average common equity
for the 12 months ended 11.5% 17.0%
________________________________
Three Months Ended September 30, 2002 and 2001
Consolidated earnings for the quarter ended September 30, 2002,
increased $3.1 million from the comparable period a year ago due
to higher earnings at the construction materials and mining, and
pipeline and energy services businesses, along with a slightly
lower seasonal loss at the natural gas distribution business.
Decreased earnings at the electric, natural gas and oil
production, and utility services businesses partially offset the
earnings increase.
Nine Months Ended September 30, 2002 and 2001
Consolidated earnings for the nine months ended September 30,
2002, decreased $24.4 million from the comparable period a year
ago due to lower earnings at the natural gas and oil production,
electric, utility services, and construction materials and
mining businesses. Increased earnings at the pipeline and
energy services, and natural gas distribution businesses
partially offset the earnings decline.
Equity Method Investment
As reported in the Company's Form 8-K which was filed on
October 23, 2002, the Company reported the press release issued
October 22, 2002, regarding earnings for the quarter ended
September 30, 2002. In this press release, the Company
reported earnings from its subsidiary's 49 percent owned
Brazilian operations in the amount of $4.0 million, largely
attributable to foreign currency gains on Brazilian real-
denominated obligations. The press release reported that while
the matter has not been finally resolved, the Company's
management has initially determined the functional currency for
the 200-megawatt natural gas fired electric generation project to
be the U.S. dollar. The Company's determination is based on the
fact that the contract revenues for the project are largely
indexed to the U.S. dollar. In addition, the majority of
expected operation and maintenance expenses as well as actual
equipment purchases are in U.S. dollars. The press release
also reported that if, however, the Brazilian real is
ultimately deemed to be the functional currency, rather than
recording a $4.0 million gain, the Company would be required
to restate earnings for the three months ended September 30,
2002 to reflect a net loss from Brazilian operations for the
third quarter of approximately $7.5 million, largely from
foreign currency losses related to U.S. dollar-denominated
obligations. This change from a gain to a loss on the equity
method investment would result in earnings and earnings per
common share, diluted, for the three months ended September 30,
2002 of $42.2 million and $.59, respectively and for the
nine months ended September 30, 2002 of $90.4 million and
$1.28, respectively.
At the time of filing this quarterly report on Form 10-Q,
the above matter has not been finally resolved. This matter is
expected to be resolved in the fourth quarter.
________________________________
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 Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
Operating revenues:
Retail sales $ 37.1 $ 37.9 $ 103.3 $ 103.5
Sales for resale and other 4.4 10.3 14.6 25.6
41.5 48.2 117.9 129.1
Operating expenses:
Fuel and purchased power 14.5 15.0 41.6 42.7
Operation and maintenance 10.8 10.5 33.7 34.0
Depreciation, depletion and
amortization 4.8 4.9 14.6 14.5
Taxes, other than income 1.8 1.8 5.6 5.6
31.9 32.2 95.5 96.8
Operating income $ 9.6 $ 16.0 $ 22.4 $ 32.3
Retail sales (million kWh) 609.9 597.3 1,669.6 1,640.4
Sales for resale (million kWh) 153.6 201.0 580.0 649.0
Average cost of fuel and
purchased power per kWh $ .018 $ .018 $ .018 $ .018
Natural Gas Distribution
Three Months Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
Operating revenues:
Sales $ 16.0 $ 17.8 $ 119.9 $ 197.9
Transportation and other .8 .9 2.8 2.9
16.8 18.7 122.7 200.8
Operating expenses:
Purchased natural gas sold 8.6 10.7 82.4 162.6
Operation and maintenance 8.5 8.3 27.0 27.8
Depreciation, depletion and
amortization 2.4 2.3 7.2 7.0
Taxes, other than income 1.2 1.2 3.8 3.8
20.7 22.5 120.4 201.2
Operating income (loss) $ (3.9) $ (3.8) $ 2.3 $ (0.4)
Volumes (MMdk):
Sales 3.1 3.0 26.2 24.6
Transportation 2.5 2.9 8.9 9.8
Total throughput 5.6 5.9 35.1 34.4
Degree days (% of normal) 82% 88% 104% 98%
Average cost of natural gas,
including transportation
thereon, per dk $ 2.73 $ 3.53 $ 3.14 $ 6.61
Utility Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
Operating revenues $ 113.4 $ 92.2 $ 338.1 $ 236.7
Operating expenses:
Operation and maintenance 104.3 80.7 311.7 206.4
Depreciation, depletion
and amortization 2.4 2.1 6.8 5.8
Taxes, other than income 3.1 2.6 10.8 6.2
109.8 85.4 329.3 218.4
Operating income $ 3.6 $ 6.8 $ 8.8 $ 18.3
Pipeline and Energy Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
Operating revenues:
Pipeline $ 26.4 $ 22.7 $ 71.4 $ 64.9
Energy services and other 2.0 42.1 44.9 424.1
28.4 64.8 116.3 489.0
Operating expenses:
Purchased natural gas sold .7 40.2 36.8 416.4
Operation and maintenance 12.1 10.4 38.8 33.9
Depreciation, depletion
and amortization 3.8 3.9 11.2 10.7
Taxes, other than income 1.3 1.6 4.4 4.6
17.9 56.1 91.2 465.6
Operating income $ 10.5 $ 8.7 $ 25.1 $ 23.4
Transportation volumes (MMdk):
Montana-Dakota 9.4 8.9 24.6 26.4
Other 20.5 19.2 52.4 46.8
29.9 28.1 77.0 73.2
Gathering volumes (MMdk) 18.8 15.2 52.4 44.0
Natural Gas and Oil Production
Three Months Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
Operating revenues:
Natural gas $ 30.2 $ 29.2 $ 87.8 $ 124.8
Oil 11.9 12.4 33.1 38.9
Other .1 .9 27.4* 5.8
42.2 42.5 148.3 169.5
Operating expenses:
Purchased natural gas sold --- .7 --- 2.4
Operation and maintenance 14.7 11.9 41.8 34.7
Depreciation, depletion
and amortization 12.3 10.3 35.2 30.4
Taxes, other than income 3.1 2.3 8.8 8.7
30.1 25.2 85.8 76.2
Operating income $ 12.1 $ 17.3 $ 62.5 $ 93.3
Production:
Natural gas (MMcf) 12,219 9,921 34,571 29,641
Oil (000's of barrels) 486 510 1,469 1,492
Average realized prices:
Natural gas (per Mcf) $ 2.48 $ 2.94 $ 2.54 $ 4.21
Oil (per barrel) $ 24.44 $ 24.33 $ 22.54 $ 26.04
* Includes the effects of a nonrecurring compromise agreement of
$27.4 million ($16.6 million after tax) in the first quarter
of 2002.
Construction Materials and Mining
Three Months Nine Months
Ended Ended
September 30, September 30,
2002 2001 2002 2001
Operating revenues:
Construction materials $ 378.6 $ 301.6 $ 701.5 $ 584.3
Coal ---** ---** ---** 12.3
378.6 301.6 701.5 596.6
Operating expenses:
Operation and maintenance 299.1 236.5 581.7 489.7
Depreciation, depletion
and amortization 14.9 12.7 39.5 34.3
Taxes, other than income 6.3 4.2 14.2 12.4
320.3 253.4 635.4 536.4
Operating income $ 58.3 $ 48.2 $ 66.1 $ 60.2
Sales (000's):
Aggregates (tons) 13,155 11,023 25,600 19,951
Asphalt (tons) 3,745 3,310 5,732 4,732
Ready-mixed concrete
(cubic yards) 951 804 2,145 1,916
Coal (tons) ---** ---** ---** 1,171
** Coal operations were sold effective April 30, 2001.
Amounts presented in the preceding tables for operating revenues,
purchased natural gas sold and operation and maintenance expenses
will not agree with the Consolidated Statements of Income due to the
elimination of intercompany transactions between the pipeline and
energy services segment and the natural gas distribution, utility
services, construction materials and mining, and natural gas and oil
production segments. The amounts relating to the elimination of
intercompany transactions for operating revenues, purchased natural
gas sold, and operation and maintenance expenses are as follows:
$8.5 million, $4.7 million and $3.8 million for the three months
ended September 30, 2002; $16.3 million, $14.7 million and $1.6
million for the three months ended September 30, 2001; $70.2
million, $59.1 million and $11.1 million for the nine months ended
September 30, 2002; and $82.4 million, $79.0 million and $3.4
million for the nine months ended September 30, 2001, respectively.
Three Months Ended September 30, 2002 and 2001
Electric
Electric earnings decreased as a result of lower average realized
sales for resale prices, which were 55 percent lower than last year,
due to a weaker demand in the sales for resale markets, and a North
Dakota retail rate reduction. Slightly offsetting the earnings
decline were increased retail sales, primarily to large industrial
and commercial customers. For further information on the North
Dakota retail rate reduction, see Prospective Information.
Natural Gas Distribution
Normal seasonal losses at the natural gas distribution business
decreased slightly as a result of somewhat higher retail sales
volumes, primarily to commercial customers, along with an interim
rate increase in Montana of $2.1 million annually, effective with
service rendered on and after September 5, 2002.
Utility Services
Utility services earnings decreased due to a slowdown in
telecommunications work and the impact of the weak economy on the
technology sector, which resulted in lower construction revenues and
margins in the Rocky Mountain and Northwest regions, as well as
lower revenues and margins in the engineering services business.
Lower equipment sales revenues and margins also added to the
earnings decrease. Partially offsetting the earnings decline were
increased workloads in the utility sector. The increase in revenues
and the related increase in operation and maintenance expense
resulted largely from businesses acquired since the comparable
period last year.
Pipeline and Energy Services
The results of the pipeline and energy services segment
could vary significantly from those discussed below, depending on
the ultimate outcome of the determination of the functional
currency of the Company's equity method investment in a natural
gas fired electric generation project in Brazil as previously
discussed.
Earnings at the pipeline and energy services business increased
largely as a result of earnings of $4.0 million from a 49 percent
equity investment in a Brazilian natural gas fired electric
generation project, largely attributable to foreign currency gains
on Brazilian real-denominated obligations, partially offset by
interest expense due to high local short-term interest rates. For
further information on the Brazilian natural gas fired electric
generation project, see Note 12 of Notes to Consolidated Financial
Statements. Also adding to the earnings increase were higher
natural gas volumes transported and gathered at higher average
rates, increased storage revenues and the absence in 2002 of the
2001 loss on the sale of the Company's energy marketing operations.
Lower technology services revenues, largely due to the depressed
telecommunications sector, partially offset the earnings increase.
The $40.1 million decrease in energy services revenue and the
related decrease in purchased natural gas sold were due primarily to
decreased energy marketing volumes resulting from the sale of the
vast majority of the Company's low-margin energy marketing
operations in the third quarter of 2001.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased due to lower
realized natural gas prices which were 16 percent lower than last
year, largely the result of significantly lower natural gas prices
in the Rocky Mountain area; higher lease operating costs resulting
from the expansion of coalbed natural gas production; increased
depreciation, depletion and amortization expense due to higher
natural gas production volumes and slightly higher rates; increased
interest expense due to higher average debt balances; and decreased
oil production of 5 percent. Increased natural gas production of
23 percent, largely from operated properties in the Rocky Mountain
area, partially offset the earnings decrease. Hedging activities
for natural gas for the third quarter of 2002 and 2001 resulted in
realized prices that were 116 and 111 percent, respectively, of what
otherwise would have been received. In addition, hedging activities
for oil for the third quarter of 2002 and 2001 resulted in realized
prices that were 95 and 102 percent, respectively, of what otherwise
would have been received.
Construction Materials and Mining
Earnings for the construction materials and mining business
increased as a result of earnings from companies acquired since the
comparable period a year ago, and higher aggregate, cement, and
ready-mixed concrete sales volumes combined with higher construction
revenues at existing operations. Existing operations accounted for
nearly 30 percent of the earnings increase. Partially offsetting
the earnings increase were higher insurance costs and higher
depreciation, depletion and amortization expense due primarily to
higher property, plant and equipment balances.
Nine Months Ended September 30, 2002 and 2001
Electric
Electric earnings decreased as a result of lower average realized
sales for resale prices, which were 44 percent lower than last year,
due to weaker demand in the sales for resale markets, a North Dakota
retail rate reduction, the absence in 2002 of 2001 insurance
recovery proceeds related to a 2000 outage at an electric generating
station and lower sales for resale volumes. Partially offsetting
the earnings decline were decreased purchased power costs, increased
retail sales volumes, primarily to residential and large industrial
customers, and decreased interest expense. For further information
on the North Dakota retail rate reduction, see Prospective
Information.
Natural Gas Distribution
Earnings at the natural gas distribution business increased as a
result of higher retail sales volumes, which were 7 percent higher
than last year, increased return on natural gas storage, demand and
prepaid commodity balances, decreased operation and maintenance
expense due primarily to decreased bad debt expense, and higher
service and repair margins. The pass-through of lower natural gas
prices resulted in the decrease in sales revenues and purchased
natural gas sold.
Utility Services
Utility services earnings decreased as a result of lower line
construction margins in the Rocky Mountain region related primarily
to decreased fiber optic construction work; decreased equipment
sales and margins; the write-off of receivables of $1.4 million
(after tax) associated with a company in the telecommunications
industry; lower construction margins in the Central region,
partially due to an unfavorable settlement of a billing dispute of
$724,000 (after tax); and decreased margins at the engineering
segment. Partially offsetting the earnings decline were increased
workloads in the Southwest and Northwest regions, and the
discontinuance of the amortization of goodwill in 2002 ($1.1 million
after tax in 2001). The increase in revenues and the related
increase in operation and maintenance expense resulted largely from
businesses acquired since the comparable period last year.
Pipeline and Energy Services
The results of the pipeline and energy services segment
could vary significantly from those discussed below, depending on
the ultimate outcome of the determination of the functional
currency of the Company's equity method investment in a natural
gas fired electric generation project in Brazil as previously
discussed.
Earnings at the pipeline and energy services business increased
as a result of higher gathering volumes at higher average rates,
increased volumes transported into storage at slightly higher
average rates and higher storage revenues. Also contributing to the
earnings improvement was the absence in 2002 of a 2001 write-off of
an investment in a software development company of $699,000 (after
tax). Partially offsetting the earnings increase were higher
operation and maintenance expense, largely related to the expansion
of the gathering system to accommodate increasing natural gas
volumes, higher depreciation, depletion and amortization expense
resulting from increased property, plant and equipment balances, and
lower technology services revenues, as previously described. Also
adding to the earnings increase were earnings of $2.2 million in
connection with domestic and international energy projects, largely
attributable to currency gains on Brazilian real-denominated
obligations. Partially offsetting the foreign currency gain were
ongoing development costs due, in part, to delays in commercial
production of power from the second 100 megawatts of installed
capacity of the natural gas fired electric generation project in
Brazil due to a delay until early 2003 in the third party delivery
of natural gas supply, and interest expense, as previously
described. The $379.2 million decrease in energy services revenue
and the related decrease in purchased natural gas sold were due
primarily to decreased energy marketing volumes resulting from the
sale of the vast majority of the Company's low-margin energy
marketing operations in the third quarter of 2001.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due to
lower realized natural gas and oil prices which were 40 percent and
13 percent lower than last year, respectively, partially offset by
higher natural gas production of 17 percent, largely from operated
properties in the Rocky Mountain area. Also adding to the earnings
decline were increased operation and maintenance expense, mainly
higher lease operating expenses resulting from the expansion of
coalbed natural gas production; increased depreciation, depletion
and amortization expense due to higher natural gas production volumes
and higher rates; and lower sales volumes of inventoried natural gas.
Partially offsetting the earnings decline were the effects of the
nonrecurring compromise agreement of $27.4 million ($16.6 million
after tax), included in operating revenue, as discussed in Note 15
of Notes to Consolidated Financial Statements. Hedging activities
for natural gas for the nine months ended September 30, 2002 and
2001 resulted in realized prices that were 109 and 99 percent,
respectively, of what otherwise would have been received. In
addition, hedging activities for oil for the nine months ended
September 30, 2002 and 2001 resulted in realized prices that were
99 and 102 percent, respectively, of what otherwise would have been
received.
Construction Materials and Mining
Earnings for the construction materials and mining business
decreased as a result of the one-time gain in 2001 from the sale of
the Company's coal operations of $11.0 million ($6.6 million after
tax), included in other income - net, as previously discussed in
Note 11 of Notes to Consolidated Financial Statements. Higher
selling, general and administrative costs, mainly due to higher
insurance and payroll costs, and higher depreciation, depletion and
amortization expense due to higher property, plant and equipment
balances, partially offset by the discontinuance of the amortization
of goodwill in 2002 ($1.2 million after tax in 2001), also added to
the earnings decline. Partially offsetting the decrease in earnings
were earnings from businesses acquired since the comparable period
last year, higher aggregate and asphalt sales volumes, and decreased
interest expense due to lower interest rates and lower average
borrowings.
Safe Harbor for Forward-looking Statements
The Company is including the following cautionary statement 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 which 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 cautionary
statements.
Forward-looking statements involve risks and uncertainties, which
could cause actual results or outcomes to differ materially from
those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties, but there can be no assurance that the Company's
expectations, beliefs or projections will be achieved or
accomplished. Furthermore, any forward-looking statement 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.
In addition to other factors and matters discussed elsewhere
herein, some important factors that could cause actual results or
outcomes for the Company to differ materially from those discussed
in forward-looking statements include: natural gas and oil
commodity prices; prevailing governmental policies and regulatory
actions with respect to allowed rates of return, financings, or
industry and rate structures; acquisition and disposal of assets or
facilities; operation and construction of plant facilities; recovery
of purchased power and purchased gas costs; present or prospective
generation; and availability of economic supplies of natural gas.
Other important factors include the level of governmental
expenditures on public projects and the timing of such projects,
changes in anticipated tourism levels, the effects of competition
(including but not limited to electric retail wheeling and
transmission costs and prices of alternate fuels and system
deliverability costs), 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, ability to acquire natural gas and oil properties,
the availability of economic expansion or development opportunities,
and political, regulatory and economic conditions and changes in
currency rates in foreign countries where the Company does business.
The business and profitability of the Company are also influenced
by economic and geographic factors, including political and economic
risks, economic disruptions caused by terrorist activities, changes
in and compliance with environmental and safety laws and policies,
weather conditions, 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,
changes in credit ratings or capital market conditions, 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, and 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 six 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 Safe
Harbor for Forward-looking Statements. 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.
- - Earnings per share, diluted, for 2002 are projected in the
$1.80 to $2.00 range. Excluding the benefit of the compromise
agreement discussed in Note 15 of Notes to Consolidated Financial
Statements, 2002 earnings per share from operations are projected to
be in the approximate range of $1.60 to $1.80. Earnings per share,
diluted, for 2002 could vary significantly from the amounts discussed
above, depending on the ultimate outcome of the determination of
the functional currency of the Company's equity method investment
in a natural gas fired electric generation project in Brazil as
previously discussed.
- - Earnings per share, diluted, for 2003 are projected in the
$1.80 to $2.05 range.
- - Weighted average diluted common shares outstanding for the
twelve months ended December 31, 2001, were 67.9 million. The
Company anticipates a 3 percent to 7 percent increase in weighted
average diluted shares outstanding by 2002 year end.
- - 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 estimates that the benefit resulting solely from
the discontinuance of goodwill amortization would be 5 cents to 6
cents per common share in 2002.
- - 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 and natural gas
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.
- - On May 2, 2002, the District Court granted Montana-Dakota's
request for a stay of a portion of the $4.3 million annual rate
reduction ordered by the NDPSC. Accordingly, Montana-Dakota
implemented an annual rate reduction of $800,000 effective with
service rendered on and after May 8, 2002, rather than the
$4.3 million annual reduction ordered by the NDPSC. The remaining
$3.5 million is subject to refund if Montana-Dakota does not prevail
in this proceeding. Reserves have been provided for the revenues
that have been collected subject to refund with respect to this
pending electric rate reduction. Oral arguments before the District
Court were held on October 9, 2002, and a ruling is expected in the
near future. For more information on this proceeding see Note 14 of
Notes to Consolidated Financial Statements.
- - A 40-megawatt natural gas fired peaking unit is scheduled to
be constructed for operation by June 1, 2003. This project is
expected to be recovered in rates and will be used to meet the
utility's need for additional generating capacity.
- - Pending regulatory approval, the Company plans to purchase
energy from a 20-megawatt, wind energy farm in North Dakota. Rate
recovery is expected.
- - Montana-Dakota is working with the State of North Dakota to
determine the feasibility of constructing a 500-megawatt lignite-
fired power plant in western North Dakota. The first preliminary
decision is expected in December 2002.
Natural gas distribution
- - Annual natural gas throughput for 2002 is expected to be
approximately 53 million decatherms, with about 40 million
decatherms from sales and 13 million decatherms from transportation,
which compares to 37 million decatherms from sales and 14 million
decatherms from transportation in 2001.
- - Montana-Dakota and Great Plains have filed applications with
state regulatory authorities in four states (Minnesota, Wyoming,
Montana and North Dakota) seeking increases in natural gas retail
rates that are in the range of 4.1 percent to 6.9 percent above
current rates. While Montana-Dakota and Great Plains believe that
they should be authorized to increase retail rates in the respective
amounts requested, there is no assurance that the increases
ultimately allowed will be for the full amounts requested in each
jurisdiction. For further information on the natural gas rate
increase applications, see Note 14 of Notes to Consolidated
Financial Statements.
Utility services
- - Revenues for this segment are expected to be approximately $450
million in 2002, a 23 percent increase over 2001. However, earnings
are estimated to decrease by approximately 50 percent from the 2001
level due to lower margins resulting from current economic
conditions combined with the second quarter 2002 write-off of
receivables and an unfavorable billing dispute settlement. Earnings
from this segment accounted for approximately 8 percent of
consolidated 2001 earnings.
Pipeline and energy services
- - In 2002, natural gas throughput from this segment, including
both transportation and gathering, is expected to increase by more
than 5 percent over the 2001 record level throughput.
- - A 247-mile pipeline to transport additional natural gas to
market and enhance the use of this segment's storage facilities is
currently under regulatory review. An application has been filed to
modify the proposed construction of this pipeline. The amended plan
seeks to reroute a portion of the line and modifies facility
construction to reduce the proposed initial maximum firm daily
design delivery capacity and revises the original construction
schedule. Depending upon the timing of the receipt of the necessary
regulatory approval, construction completion could occur as early as
late 2003.
- - MDU International continues its efforts to complete the
financing for a 200-megawatt natural gas fired electric generation
project in Brazil. The first 100 megawatts have begun commercial
production and the second 100 megawatts are scheduled to begin
commercial production early in 2003. Petrobras, the purchaser of
the output from the project, commenced making capacity payments in
the third quarter. Earnings for 2002 from the natural gas fired
electric generation project in Brazil could vary significantly
depending on the ultimate outcome of the determination of the
functional currency of the Company's equity method investment in
this project as previously discussed.
- - On November 1, 2002, the Company's independent power production
group purchased 213 megawatts of natural gas fired electric
generating facilities. Ninety-five percent of the facilities'
output is sold to a non-affiliated utility under long-term power
purchase contracts. The acquisition is expected to be funded with
long-term debt and equity.
- - 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 September 30, 2002, the Company's investment in
this project was approximately $22.4 million.
Natural gas and oil production
- - This segment anticipates combined natural gas and oil
production in 2002 to be approximately 10 percent to 15 percent
higher than in 2001.
- - In 2003, this segment expects a combined production increase in
excess of 20 percent over 2002 levels.
- - This segment expects to drill approximately 250 wells in 2002.
- - Natural gas prices in the Rocky Mountain Region for November
and December 2002 reflected in the Company's 2002 earnings guidance
are in the range of $2.00 to $2.50 per Mcf. The Company's estimates
for natural gas prices on the NYMEX for November and December 2002
reflected in the Company's 2002 earnings guidance are in the range
of $3.50 to $4.00 per Mcf. During the first nine months of 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 November and December 2002 reflected
in the Company's 2002 earnings guidance are in the range of $28 to
$30 per barrel.
- - This segment has hedged a portion of its 2002 production. The
Company has entered into swap agreements and fixed price forward
sales representing approximately 35 percent to 40 percent of 2002
estimated annual natural gas production. These natural gas swaps
are at various indices and range from a low CIG index of $2.73 to a
high NYMEX price of $4.34. The Company has also entered into oil
swap agreements at average NYMEX prices in the range of $24.80 to
$25.90 per barrel, representing approximately 30 percent to 35
percent of the Company's 2002 estimated annual oil production.
- - The Company has hedged a portion of its 2003 production. The
Company has entered into costless collars, a natural gas swap and
fixed price forward sales, representing approximately 35 percent to
40 percent of 2003 estimated annual natural gas production. The
costless collars and swap are at various indices and range from a
low CIG index of $2.94 to a high Ventura index of $4.30 per Mcf.
- - For 2003, the Company's estimates for natural gas prices in the
Rocky Mountain Region are in the range of $2.50 to $3.00 per Mcf and
estimates for natural gas prices on the NYMEX are in the range of
$3.00 to $3.50.
- - The Company's estimates for NYMEX crude oil prices are in the
range of $20 to $25 per barrel for 2003.
- - The Company has hedged a portion of its 2003 oil production.
The Company has entered into a costless collar at NYMEX prices with
a floor of $24.50 and a cap of $27.15 representing approximately
15 percent to 20 percent of 2003 estimated annual oil production.
Construction materials and mining
- - Excluding the effects of potential future acquisitions,
aggregate volumes are expected to increase by approximately 18
percent to 23 percent in 2002 and asphalt and ready-mixed concrete
volumes are expected to increase by 15 percent to 20 percent and 5
percent to 10 percent, respectively, in 2002.
- - Work has begun on a $167 million joint venture harbor deepening
project in Los Angeles. One of the Company's subsidiaries is
responsible for approximately one-half of this project and will be
supplying rock from its Catalina Island quarry. Another subsidiary
has begun work on a multi-year resort project in the State of
Washington.
- - Revenues for this segment are expected to exceed $900 million
in 2002.
- - Revenues are expected to grow by 5 percent to 10 percent in
2003.
New Accounting Standards
In June 2001, the FASB approved SFAS No. 143. For further
information on SFAS No. 143, see Note 6 of Notes to Consolidated
Financial Statements.
In June 2001, the FASB approved SFAS No. 142. Under SFAS No.
142, goodwill and other intangible assets with indefinite lives are
no longer amortized but are reviewed annually, or more frequently if
impairment issues arise, for impairment. As of December 31, 2001,
the Company had unamortized goodwill of $174.0 million that was
subject to the provisions of SFAS No. 142. Had SFAS No. 142 been in
effect for 2001, earnings would have been $4.2 million higher. For
further information on SFAS No. 142, see Note 9 of Notes to
Consolidated Financial Statements.
In April 2002, the FASB approved SFAS No. 145. For further
information on SFAS No. 145, see Note 6 of Notes to Consolidated
Financial Statements.
In June 2002, the EITF adopted the position in EITF No. 02-3.
For further information on EITF No. 02-3, see Note 6 of Notes to
Consolidated Financial Statements.
In June 2002, the FASB approved SFAS No. 146. For further
information on SFAS No. 146, see Note 6 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 production properties, revenue recognition, derivatives,
purchase accounting and accounting for the effects of regulation.
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, 2001. 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, 2001.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows from operating activities in the first nine months of
2002 decreased $57.2 million from the comparable 2001 period,
primarily due to a decrease in cash from changes in working capital
items of $53.3 million and the decrease in net income of $24.3
million. The working capital decrease was primarily due to lower
natural gas prices compared to the same period last year. Higher
depreciation, depletion and amortization expense of $11.8 million
resulting largely from increased property, plant and equipment
balances partially offset the decrease in cash flows from operating
activities.
Investing activities --
Cash flows used in investing activities in the first nine months
of 2002 decreased $78.2 million compared to the comparable period in
2001, the result of a decrease in net capital expenditures (capital
expenditures, acquisitions, net of cash acquired, and net proceeds
from the sale or disposition of property). Net capital expenditures
exclude the noncash transactions related to acquisitions, including
the issuance of the Company's equity securities. The noncash
transactions were $46.0 million and $57.3 million in the first nine
months of 2002 and 2001, respectively.
Financing activities --
Financing activities resulted in a decrease in cash flows for the
first nine months of 2002 of $41.3 million compared to the
comparable 2001 period. This decrease was largely due to the
decrease in issuance of long-term debt of $90.8 million and the
decrease in proceeds from issuance of common stock of $52 million.
This decrease was partially offset by a decrease in the repayment of
long-term debt of $88 million.
Capital expenditures
Net capital expenditures, including the issuance of the Company's
equity securities, for the first nine months of 2002 were $267.6
million and are estimated to be approximately $420 million for the
year 2002, including those for acquisitions, system upgrades,
routine replacements, service extensions, routine equipment
maintenance and replacements, land and building improvements,
pipeline and gathering expansion projects, the further enhancement
of natural gas and oil production and reserve growth, power
generation opportunities and other growth opportunities.
Approximately 30 percent to 35 percent of estimated net capital
expenditures for 2002 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 2002
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, a
revolving credit and term loan agreement, a commercial paper credit
facility at Centennial, as described below, and through the issuance
of long-term debt and the Company's equity securities.
The estimated 2002 capital expenditures referred to above include
completed 2002 acquisitions involving construction materials and
mining businesses in Minnesota and Montana, an energy development
company in Montana, utility services companies in California and
Ohio, and natural gas fired electric generation facilities in Colorado.
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
MDU Resources Group, Inc.
The Company has a revolving credit and term loan agreement with
various banks that allows for borrowings of up to $40 million. In
addition, the Company has unsecured bank lines of credit aggregating
$60 million. Under the credit and term loan agreement, $23 million
was outstanding at September 30, 2002. There were no outstanding
borrowings under the Company's bank lines of credit at September 30,
2002. The borrowings by the Company under the credit and term loan
agreement, which allows for subsequent borrowings up to a term of
one year, are classified as long term as the Company intends to
refinance these borrowings on a long-term basis. The Company
intends to renew or replace the existing credit and term loan
agreement, which expires on December 31, 2002. The Company
also has arrangements with commercial paper dealers to sell
commercial paper from time to time, and has recently requested
regulatory authority to incur indebtedness in the form of bank loans
and commercial paper up to $125 million in total.
The Company's goal is to maintain acceptable credit ratings under
its credit agreements and individual bank lines of credit in order
to access the capital markets through the issuance of commercial
paper. If the Company were to experience a minor downgrade of its
credit rating, the Company 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 the Company does not currently anticipate, it may
need to borrow under its committed bank lines.
To the extent the Company needs to borrow under its committed
bank lines, it would be expected to incur increased annualized
interest expense on its variable rate debt. This was not applicable
for the calendar year 2002 as there were no variable rate borrowings
at September 30, 2002.
On an annual basis, the Company negotiates the placement of its
individual bank lines of credit that provide credit support to
access the capital markets. In the event the Company were unable to
successfully negotiate the bank credit facilities, or in the event
the fees on such facilities became too expensive, which the Company
does not currently anticipate, the Company would seek alternative
funding. One source of alternative funding might involve the
securitization of certain Company assets.
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 September 30, 2002, the Company could have issued
approximately $319 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.5 times and 5.3 times for the twelve months ended
September 30, 2002 and December 31, 2001, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 7.3 times and 8.5 times for the twelve months ended September
30, 2002 and December 31, 2001, respectively. Common stockholders'
equity as a percent of total capitalization was 58 percent at
September 30, 2002 and December 31, 2001.
Centennial Energy Holdings, Inc.
Centennial has a revolving credit agreement (Centennial credit
agreement) with various banks that supports $305 million of
Centennial's $350 million commercial paper program. There were no
outstanding borrowings under the Centennial credit agreement at
September 30, 2002. Under the Centennial commercial paper program,
$233.6 million was outstanding at September 30, 2002. The
Centennial commercial paper borrowings are classified as long term
as Centennial intends to refinance these borrowings on a long-term
basis through continued Centennial commercial paper borrowings and
as further supported by the Centennial credit agreement, which
allows for subsequent borrowings up to a term of one year.
Centennial intends to renew the Centennial credit agreement, which
expires September 26, 2003, on an annual basis.
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, $261.2 million was outstanding at
September 30, 2002. On October 22, 2002, Centennial borrowed an
additional $50 million under the terms of this agreement. The $50
million in proceeds were used for partial payment of an acquisition
and to pay down Centennial commercial paper program borrowings.
Centennial's goal is to maintain acceptable credit ratings under
its credit agreement in order to access the capital markets through
the issuance of commercial paper. If Centennial were to experience
a minor downgrade of its credit rating, it would not anticipate any
change in its ability to access the capital markets. However, in
such event, Centennial would expect a nominal basis point increase
in overall interest rates with respect to its cost of borrowings.
If Centennial were to experience a significant downgrade of its
credit ratings, which it does not currently anticipate, it may need
to borrow under its committed bank lines.
To the extent Centennial needs to borrow under its committed
bank lines, it would be expected to incur increased annualized
interest expense on its variable rate debt by approximately $350,000
(after tax) for the calendar year 2002 based on September 30, 2002
variable rate borrowings. Based on Centennial's overall interest
rate exposure at September 30, 2002, this change would not have a
material affect on the Company's results of operations.
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, limitations on
priority debt, limitations on sale of assets and limitations on
loans and investments. Centennial and such subsidiaries were in
compliance with these covenants and met the required conditions at
September 30, 2002. In the event Centennial or such subsidiaries do
not comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued as previously
described.
The Centennial credit agreement and the Centennial uncommitted
long-term master shelf agreement contain cross-default provisions.
These provisions state that if Centennial or any subsidiary of
Centennial fails to make any payment with respect to any
indebtedness or contingent obligation, in excess of a specified
amount, under any agreement which 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.
MDU Resources International, Inc.
MDU International has a credit agreement that allows for
borrowings of up to $25 million. Under this agreement, $10 million
was outstanding at September 30, 2002. MDU International intends to
renew this credit agreement, which expires June 30, 2003, on an
annual basis.
In order to borrow under MDU International's credit facilities,
MDU International must be in compliance with the applicable
covenants and certain other conditions. The significant covenants
include limitations on sale of assets and limitations on loans and
investments. MDU International was in compliance with these
covenants and met the required conditions at September 30, 2002. In
the event MDU International 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, 2001. For more
information on contractual obligations and commercial commitments,
see Item 7 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2001.
Certain subsidiaries of the Company have financial guarantees
outstanding at September 30, 2002. These guarantees as of September
30, 2002, are approximately $31.2 million, of which approximately
$27.8 million pertain to Centennial's guarantee of certain
obligations in connection with the natural gas fired electric
generation station in Brazil, as discussed in Notes 10 and 15 of
Notes to Consolidated Financial Statements in the 2001 Annual Report
and Items 2 and 3 of this Quarterly Report on Form 10-Q. As of
September 30, 2002, with respect to these guarantees, there were
approximately $27.8 million outstanding through 2003, $1.4 million
outstanding through 2004 and $2.0 million outstanding thereafter.
Approval of audit and non-audit services
On November 12, 2002, the Company's audit committee pre-
approved certain audit services relating to comfort letters and
consents in connection with registration statements and other
Securities and Exchange Commission required filings and audit
reviews in connection with such filings, audit reviews in connection
with business combinations, and additional audit services required
in connection with quarterly reviews and annual audits. The audit
committee also approved certain non-audit services, relating to tax
services in connection with domestic and international operations,
and training on accounting and Securities and Exchange Commission
compliance. The approved services, to be performed by the Company's
auditor, Deloitte & Touche LLP, for the period November 12, 2002 to
December 31, 2003, are expected to result in total fees of up to
$100,000.
Also on that date, the audit committee, in compliance with the
"de minimus" exception in the Sarbanes-Oxley Act, approved certain
other non-audit services relating to tax services in connection with
domestic and international operations of approximately $5,000 that
had been performed by the Company's auditors.
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 --
The Company utilizes derivative instruments, including natural
gas and oil price swap and natural gas collar agreements, to manage
a portion of the market risk associated with fluctuations in the
price of natural gas and oil on the Company'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, 2001, and Notes to
Consolidated Financial Statements in this Form 10-Q.
The following table summarizes hedge agreements entered into by
certain wholly owned subsidiaries of the Company, as of
September 30, 2002. These agreements call for the subsidiaries to
receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2002 $ 3.73 4,225 $1,548
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2002 $ 24.52 194 $(1,061)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2003 $3.24/$3.90 12,118 $(1,651)
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, 2001. 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, 2001.
Foreign currency risk --
A subsidiary of the Company has a 49 percent equity investment
in a 200 megawatt natural gas fired electric generation project
(Project) in Brazil which has a portion of its borrowings and
payables denominated in Brazilian real. The subsidiary has exposure
to currency exchange risk as a result of fluctuations in currency
exchange rates between the U.S. dollar and the Brazilian real. For
further information on this investment, see Note 12 of Notes to
Consolidated Financial Statements.
The effects of changes in currency exchange rates with respect
to the Project's Brazilian real denominated obligations are
reflected in net income. At September 30, 2002, the Project had
Brazilian real obligations of approximately US$20.5 million. If, for
example, the value of the Brazilian real increased in relation to
the U.S. Dollar by 10 percent, the subsidiary, with respect to its
interest in the Project, would record a foreign currency translation
loss in net income of approximately $1.2 million based on the
Brazilian real denominated obligations at September 30, 2002. In
addition to the Brazilian real denominated obligations, the Project
had $44.1 million of third party U.S. dollar denominated obligations
at September 30, 2002.
The subsidiary's investment in this Project at September 30,
2002 was $27.8 million. In addition to the subsidiary's investment,
Centennial has guaranteed Project obligations and loans of
approximately $27.8 million as of September 30, 2002.
The subsidiary is managing a portion of its foreign currency
exchange risk through contractual provisions that are largely
indexed to the U.S. dollar contained in the Project's power purchase
agreement with Petrobras. On August 12, 2002, the subsidiary
entered into a foreign currency collar agreement for a notional
amount of $21.3 million with a fixed price floor of R$3.10 and a
fixed price ceiling of R$3.40 to manage a portion of its foreign
currency risk. The term of the collar agreement is from August 12,
2002 through February 3, 2003, and the collar agreement settles on
February 3, 2003. Gains or losses on this derivative instrument are
recorded in earnings each period. The fair value of the foreign
currency collar agreement at September 30, 2002 was $415,000
($260,000 after tax).
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. 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
The 11 natural gas producers filed a petition for writ of
certiorari with the Supreme Court of the United States, which was
docketed on August 21, 2002. On October 21, 2002, the Supreme Court
of the United States denied the writ of certiorari.
For more information on the above legal action see Note 15 of
Notes to Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between July 1, 2002 and September 30, 2002, the Company issued
15,495 shares of Common Stock, $1.00 par value, as part of final
adjustments with respect to acquisitions in a prior period. The
Common Stock issued by the Company in these transactions was issued
in private sales exempt from registration pursuant to Section 4(2)
of the Securities Act of 1933. The former owners of the businesses
acquired, and now shareholders of the Company, are accredited
investors and have acknowledged that they would hold the Company's
Common Stock as an investment and not with a view to distribution.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
3(a) Certificate of Designations of Series B Preference
Stock of MDU Resources Group, Inc.
10(a) Change of Control Employment Agreement between the
Company and John K. Castleberry
10(b) Change of Control Employment Agreement between the
Company and Cathleen M. Christopherson
10(c) Change of Control Employment Agreement between the
Company and Richard A. Espeland
10(d) Change of Control Employment Agreement between the
Company and Terry D. Hildestad
10(e) Change of Control Employment Agreement between the
Company and Lester H. Loble, II
10(f) Change of Control Employment Agreement between the
Company and Vernon A. Raile
10(g) Change of Control Employment Agreement between the
Company and Warren L. Robinson
10(h) Change of Control Employment Agreement between the
Company and William E. Schneider
10(i) Change of Control Employment Agreement between the
Company and Ronald D. Tipton
10(j) Change of Control Employment Agreement between the
Company and Martin A. White
10(k) Change of Control Employment Agreement between the
Company and Robert E. Wood
12 Computation of Ratio of Earnings to Fixed Charges and Combined
Fixed Charges and Preferred Stock Dividends
99 Statement Pursuant to Section 906 of Sarbanes - Oxley
Act of 2002
b) Reports on Form 8-K
Form 8-K was filed on August 14, 2002. Under Item 7 -- Financial
Statements and Exhibits and Item 9 -- Regulation FD Disclosure,
the Company reported the sworn statements of the Principal
Executive Officer and Principal Financial Officer, in compliance
with the Securities and Exchange Commission's Order No. 4-460.
Form 8-K was filed on October 23, 2002. Under Item 5 -- Other
Events, the Company reported the press release issued October 22,
2002, regarding earnings for the quarter ended September 30,
2002.
Form 8-K was filed on November 5, 2002. Under Item 5 -- Other
Events and Item 7 -- Financial Statements and Exhibits, the
Company reported the purchase of 213 megawatts of natural gas
fired electric generating facilities.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, as amended, the registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE: November 14, 2002 BY /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President,
Treasurer and Chief
Financial Officer
BY /s/ Vernon A. Raile
Vernon A. Raile
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: November 14, 2002 /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: November 14, 2002 /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President, Treasurer
and Chief Financial Officer
EXHIBIT INDEX
Exhibit No.
3(a) Certificate of Designations of Series B Preference
Stock of MDU Resources Group, Inc.
10(a) Change of Control Employment Agreement between the
Company and John K. Castleberry
10(b) Change of Control Employment Agreement between the
Company and Cathleen M. Christopherson
10(c) Change of Control Employment Agreement between the
Company and Richard A. Espeland
10(d) Change of Control Employment Agreement between the
Company and Terry D. Hildestad
10(e) Change of Control Employment Agreement between the
Company and Lester H. Loble, II
10(f) Change of Control Employment Agreement between the
Company and Vernon A. Raile
10(g) Change of Control Employment Agreement between the
Company and Warren L. Robinson
10(h) Change of Control Employment Agreement between the
Company and William E. Schneider
10(i) Change of Control Employment Agreement between the
Company and Ronald D. Tipton
10(j) Change of Control Employment Agreement between the
Company and Martin A. White
10(k) Change of Control Employment Agreement between the
Company and Robert E. Wood
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock Dividends
99 Statement Pursuant to Section 906 of Sarbanes -
Oxley Act of 2002